Hydro One (HRNNF) 2025 income, cash flow and debt profile improve

Rhea-AI Filing Summary

Hydro One Limited reports audited 2025 results, showing higher revenue and earnings than 2024. Revenue rose to $9,041 million from $8,484 million, driven by both distribution and transmission. Net income increased to $1,349 million from $1,165 million, with basic EPS up to $2.23 from $1.93.

Operating costs grew more slowly than revenue, lifting income before tax to $1,568 million from $1,346 million. Cash from operating activities was strong at $2,695 million, supporting capital investment and dividends of $1.31 per share. Net cash used in investing reached $3,514 million, mainly for grid and technology investments.

Total assets increased to $39,671 million, while total liabilities were $26,925 million, including long-term debt of $18,092 million. Regulatory assets were $3,867 million and regulatory liabilities $1,851 million, reflecting the impact of Ontario rate regulation. KPMG LLP issued an unqualified opinion on the consolidated financial statements and highlighted the evaluation of regulatory assets and liabilities under ASC 980 as a critical audit matter.

Positive

• Stronger profitability and EPS growth: Net income rose to $1,349 million from $1,165 million and basic EPS increased to $2.23 from $1.93, showing earnings growing faster than revenue.
• Robust operating cash flow supporting payouts and investment: Net cash from operating activities reached $2,695 million versus $2,534 million, more than covering $788 million of common dividends and significant capital and equity investments.

Negative

• None.

Insights

Utility sector equity analyst

Hydro One posts modest top-line growth with stronger profit and cash generation in 2025.

Hydro One delivered 2025 revenue of $9,041 million, up from $8,484 million, while net income increased to $1,349 million from $1,165 million. Earnings per share rose to $2.23 basic versus $1.93, indicating solid profit expansion relative to revenue growth.

Cost discipline helped: operating, maintenance and administration expense declined to $1,206 million from $1,308 million even as depreciation and financing costs rose with ongoing capital investment. Operating cash flow of $2,695 million comfortably funded common dividends of $788 million and supported substantial capital spending and an equity investment in EWT LP.

Regulation remains central to the thesis. Regulatory assets of $3,867 million and liabilities of $1,851 million underscore dependence on Ontario Energy Board decisions, and KPMG’s critical audit matter focuses on judgments around probability of recovery and refund. Subsequent rate and capital-allocation disclosures in future periods will shape how sustainable this earnings and dividend profile appears.

Form 6-K: How Foreign Companies Report to the SEC →

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 6-K

REPORT OF FOREIGN PRIVATE ISSUER

Pursuant to Rule 13a-16 or 15d-16 under

the Securities Exchange Act of 1934

For the month of: February 2026

Commission File Number: 333-225519-01

HYDRO ONE LIMITED

(Translation of Registrant’s name into English)

483 Bay Street, South Tower, 8th Floor, Toronto Ontario M5G 2P5 Canada

(Address of principal executive offices)

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.

Form 20-F  ☐            Form 40-F  ☒

EXHIBIT INDEX

99.1						Audited consolidated financial statements of the Registrant as at and for the years ended December 31, 2025 and 2024, and Auditors' Report thereon dated February 12, 2026
99.2						Management’s Discussion and Analysis of the Registrant as at and for the year ended December 31, 2025

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

						HYDRO ONE LIMITED
						/s/ Harry Taylor
						Name: Harry Taylor
						Title:   Executive Vice President, Chief Financial and Regulatory Officer
						Date:			February 13, 2026

HYDRO ONE LIMITED

MANAGEMENT’S REPORT

The Consolidated Financial Statements, Management’s Discussion and Analysis (MD&A) and related financial information have been prepared by the management of Hydro One Limited (Hydro One or the Company). Management is responsible for the integrity, consistency and reliability of all such information presented. The Consolidated Financial Statements for the year ended December 31, 2025 and accompanying notes thereto (together, the Consolidated Financial Statements) have been prepared in accordance with United States (U.S.) generally accepted accounting principles (GAAP) and applicable securities legislation. The MD&A has been prepared in accordance with National Instrument 51-102.

The preparation of the Consolidated Financial Statements and information in the MD&A involves the use of estimates and assumptions based on management’s judgment, particularly when transactions affecting the current accounting period cannot be finalized with certainty until future periods. Estimates and assumptions are based on historical experience, current conditions and various other assumptions believed to be reasonable in the circumstances, with critical analysis of the significant accounting policies followed by the Company as described in Note 2 to the Consolidated Financial Statements. The preparation of the Consolidated Financial Statements and the MD&A includes information regarding the estimated impact of future events and transactions. The MD&A also includes information regarding sources of liquidity and capital resources, operating trends, risks and uncertainties. Actual results in the future may differ materially from the present assessment of this information because future events and circumstances may not occur as expected.

Management is responsible for establishing and maintaining adequate disclosure controls and procedures and internal control over financial reporting as described in the annual MD&A. Management evaluated the effectiveness of the design and operation of disclosure controls and procedures, and internal control over financial reporting based on the framework and criteria established in the Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on that evaluation, management concluded that the Company’s internal control over financial reporting was effective at a reasonable level of assurance as at December 31, 2025. As required, the results of that evaluation were reported to the Audit Committee of the Hydro One Board of Directors.

The Consolidated Financial Statements have been audited by KPMG LLP, an independent registered public accounting firm appointed by the shareholders of the Company. The external auditors’ responsibility is to express their opinion on whether the Consolidated Financial Statements are fairly presented in all material respects in conformity with U.S. generally accepted accounting principles. The Report of Independent Registered Public Accounting Firm outlines the scope of their examination and their opinion.

The Hydro One Board of Directors, through its Audit Committee, is responsible for ensuring that management fulfills its responsibilities for financial reporting and internal control over financial reporting and disclosure. The Audit Committee of Hydro One met periodically with management, the internal auditors and the external auditors to satisfy itself that each group had properly discharged its respective responsibility with respect to the Consolidated Financial Statements before recommending approval by the Board of Directors. The external auditors had direct and full access to the Audit Committee, with and without the presence of management, to discuss their audit findings.

On behalf of Hydro One’s management:

David Lebeter						Harry Taylor
President and Chief Executive Officer						Executive Vice President, Chief Financial and Regulatory Officer

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HYDRO ONE LIMITED

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors of Hydro One Limited:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Hydro One Limited (the Company) as of December 31, 2025 and 2024, the related consolidated statements of operations and comprehensive income, changes in equity, and cash flows for each of the years then ended, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of operations and its cash flows for each of the years then ended, in conformity with U.S. generally accepted accounting principles.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

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

Evaluation of Regulatory Assets and Liabilities and the impact of rate regulation on the consolidated financial statements

As discussed in Note 2 to the consolidated financial statements, the Company accounts for its regulated operations in accordance with Financial Accounting Standards Board Accounting Standard Codification Topic 980, Regulated Operations (ASC 980). Under ASC 980, the actions of the Company’s regulator may result in the recognition of revenue and costs in time periods that are different than non-rate-regulated enterprises. When this occurs, the Company records incurred and allowed costs that it has assessed are probable of recovery in future electricity rates as regulatory assets or property, plant and equipment. Obligations imposed or probable to be imposed by the regulator to refund previously collected revenue or expenditure of revenue collected from customers on future costs are recorded as regulatory liabilities. As disclosed in Note 11 to the consolidated financial statements, as of December 31, 2025, the Company’s regulatory assets were $3,867 million and regulatory liabilities were $1,851 million.

We identified the evaluation of regulatory assets and liabilities and the impact of rate regulation as a critical audit matter. Accounting for regulated operations under ASC 980 affects multiple financial statement accounts and disclosures in the Company’s consolidated financial statements. Assessing the accounting for regulated operations requires significant auditor judgment due to interpretations of regulatory decisions and judgments involved in evaluating the Company’s assessment of the probability associated with recovery of regulatory assets and imposition of regulatory liabilities.

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and implementation and tested the operating effectiveness of certain internal controls over the Company’s regulatory accounting process. This included controls over the evaluation of the probability of (1) the recovery in future rates of costs deferred as regulatory assets, and (2) a refund of previously collected revenue or expenditure of revenue collected from customers on future costs that should be reported as regulatory liabilities, and controls over the monitoring and evaluation of regulatory developments that may affect the probability of recovering costs in future rates or imposing of regulatory liabilities. We evaluated the Company’s assessment of the probability of recovery of the carrying amount for a selection of regulatory assets and for the imposition of a

2

HYDRO ONE LIMITED

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

selection of regulatory liabilities, through consideration of selected regulatory proceedings, decisions and accounting orders. For a selection of regulatory proceedings, decisions and accounting orders, we read the Company’s assessment and interpretations. For a selection of regulatory assets and liabilities, we recalculated the amounts recorded based on methodologies approved by the regulator and agreed the data used in the calculations to the Company’s underlying books and records. We compared the amounts calculated by the Company to the amounts recorded in the consolidated financial statements.

/s/ KPMG LLP

Chartered Professional Accountants, Licensed Public Accountants

We have served as the Company’s auditor since 2008.

Toronto, Canada

February 12, 2026

3

HYDRO ONE LIMITED

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

For the years ended December 31, 2025 and 2024

Year ended December 31 (millions of Canadian dollars, except per share amounts)									2025			2024
Revenues
Distribution (includes $447 related party revenues; 2024 - $427) (Note 27)									6,557			6,175
Transmission (includes $2,390 related party revenues; 2024 - $2,254) (Note 27)									2,429			2,269
Other (Note 27)									55			40
									9,041			8,484
Costs
Purchased power (includes $3,036 related party costs; 2024 - $2,705) (Note 27)									4,486			4,143
Operation, maintenance and administration (Note 27)									1,206			1,308
Depreciation, amortization and asset removal costs (Note 4)									1,111			1,066
									6,803			6,517
Income before financing charges, equity income and income tax expense									2,238			1,967
Financing charges (Note 5)									679			621
Equity income (Note12)									9			—
Income before income tax expense									1,568			1,346
Income tax expense (Note 6)									219			181
Net income									1,349			1,165
Other comprehensive income (loss)									3			(9)
Comprehensive income									1,352			1,156
Net income attributable to:
Noncontrolling interest (Note 26)									10			9
Common shareholders									1,339			1,156
									1,349			1,165
Comprehensive income attributable to:
Noncontrolling interest (Note 26)									10			9
Common shareholders									1,342			1,147
									1,352			1,156
Earnings per common share (Note 24)
Basic									$2.23			$1.93
Diluted									$2.23			$1.92
Dividends per common share declared (Note 23)									$1.31			$1.24

See accompanying notes to Consolidated Financial Statements.

4

HYDRO ONE LIMITED

CONSOLIDATED BALANCE SHEETS

At December 31, 2025 and 2024

As at December 31 (millions of Canadian dollars)			2025			2024
Assets
Current assets:
Cash and cash equivalents			549			716
Accounts receivable (Note 7)			1,083			911
Due from related parties			409			325
Other current assets (Note 8)			133			165
			2,174			2,117
Property, plant and equipment (Note 9)			31,450			29,093
Other long-term assets:
Regulatory assets (Note 11)			3,857			3,503
Deferred income tax assets (Note 6)			135			127
Intangible assets (Note 10)			654			661
Goodwill			378			373
Other assets (Note 12)			1,023			808
			6,047			5,472
Total assets			39,671			36,682
Liabilities
Current liabilities:
Short-term notes payable (Notes 15 & 17)			100			200
Long-term debt payable within one year (Notes 15, 16 & 17)			925			1,150
Accounts payable and other current liabilities (Note 13)			2,086			1,809
Due to related parties			479			342
			3,590			3,501
Long-term liabilities:
Long-term debt (Notes 15, 16 & 17)			18,092			16,329
Regulatory liabilities (Note 11)			1,621			1,476
Deferred income tax liabilities (Note 6)			1,799			1,452
Other long-term liabilities (Note 14)			1,823			1,751
			23,335			21,008
Total liabilities			26,925			24,509
Contingencies and Commitments (Notes 29 & 30)
Subsequent Events (Note 32)
Noncontrolling interest subject to redemption (Note 26)			19			19
Equity
Common shares			5,721			5,713
Additional paid-in capital			25			28
Retained earnings			6,911			6,360
Accumulated other comprehensive loss			(9)			(12)
Hydro One shareholders’ equity			12,648			12,089
Noncontrolling interest (Note 26)			79			65
Total equity			12,727			12,154
			39,671			36,682

See accompanying notes to Consolidated Financial Statements.

On behalf of the Board of Directors:

Melissa Sonberg						Helga Reidel
Chair						Chair, Audit Committee

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HYDRO ONE LIMITED

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

For the years ended December 31, 2025 and 2024

Year ended December 31, 2025 (millions of Canadian dollars)			Common Shares						Additional Paid-in Capital			Retained Earnings			Accumulated Other Comprehensive Loss			Hydro One Shareholders’ Equity			Non-controlling Interest (Note 26)			Total Equity
January 1, 2025			5,713						28			6,360			(12)			12,089			65			12,154
Net income			—						—			1,339			—			1,339			8			1,347
Other comprehensive income			—						—			—			3			3			—			3
Distributions to noncontrolling interest (Note 26)			—						—			—			—			—			(10)			(10)
Contributions from sale of noncontrolling interest			—						—			—			—			—			16			16
Dividends on common shares (Note 23)			—						—			(788)			—			(788)			—			(788)
Common shares issued			8						(8)			—			—			—			—			—
Stock-based compensation			—						5			—			—			5			—			5
December 31, 2025			5,721						25			6,911			(9)			12,648			79			12,727

Year ended December 31, 2024 (millions of Canadian dollars)			Common Shares						Additional Paid-in Capital			Retained Earnings			Accumulated Other Comprehensive Loss			Hydro One Shareholders’ Equity			Non-controlling Interest (Note 26)			Total Equity
January 1, 2024			5,706						30			5,947			(3)			11,680			65			11,745
Net income			—						—			1,156			—			1,156			7			1,163
Other comprehensive loss			—						—			—			(9)			(9)			—			(9)
Distributions to noncontrolling interest (Note 26)			—						—			—			—			—			(7)			(7)
Dividends on common shares (Note 23)			—						—			(743)			—			(743)			—			(743)
Common shares issued			7						(7)			—			—			—			—			—
Stock-based compensation			—						5			—			—			5			—			5
December 31, 2024			5,713						28			6,360			(12)			12,089			65			12,154

See accompanying notes to Consolidated Financial Statements.

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HYDRO ONE LIMITED

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the years ended December 31, 2025 and 2024

Year ended December 31 (millions of Canadian dollars)									2025			2024
Operating activities
Net income									1,349			1,165
Environmental expenditures (Note 4)									(3)			(11)
Adjustments for non-cash items:
Depreciation and amortization (Note 4)									966			920
Regulatory assets and liabilities									240			81
Deferred income tax expense									76			140
Other									14			(10)
Changes in non-cash balances related to operations (Note 28)									53			249
Net cash from operating activities									2,695			2,534
Financing activities
Long-term debt issued									2,698			2,781
Long-term debt repaid (Note 15)									(1,150)			(700)
Short-term notes issued									6,070			2,810
Short-term notes repaid									(6,170)			(2,890)
Dividends paid on common shares (Note 23)									(788)			(743)
Distributions paid to noncontrolling interest									(12)			(10)
Contributions received from sale of noncontrolling interest									16			—
Costs to obtain financing									(12)			(15)
Net cash from financing activities									652			1,233
Investing activities
Capital expenditures (Note 28)
Property, plant and equipment									(2,970)			(2,720)
Intangible assets									(80)			(88)
Additions to future use assets									(213)			(323)
Investment in equity investees (Note 12)									(261)			—
Capital contributions received (Note 28)									3			2
Other									7			(1)
Net cash used in investing activities									(3,514)			(3,130)
Net change in cash and cash equivalents									(167)			637
Cash and cash equivalents, beginning of year									716			79
Cash and cash equivalents, end of year									549			716

See accompanying notes to Consolidated Financial Statements.

7

HYDRO ONE LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025 and 2024

1.    DESCRIPTION OF THE BUSINESS

Hydro One Limited (Hydro One or the Company) was incorporated on August 31, 2015, under the Business Corporations Act (Ontario). On October 31, 2015, the Company acquired Hydro One Inc., a company previously wholly-owned by the Province of Ontario (Province). As at December 31, 2025, the Province held approximately 47.1% (2024 - 47.1%) of the common shares of Hydro One. The businesses of Hydro One are comprised of the following three segments:

•The Transmission segment consists of owning and operating Hydro One’s transmission system which transmits high voltage electricity across the province, interconnecting local distribution companies and certain large directly connected industrial customers throughout the Ontario electricity grid. The transmission business consists of the transmission system operated by Hydro One Inc.’s rate-regulated subsidiaries, Hydro One Networks Inc. (Hydro One Networks), Hydro One Sault Ste. Marie LP (HOSSM), an approximate 80% (2024 - 100%) interest in Chatham x Lakeshore Limited Partnership (CLLP), an approximate 66% interest in B2M Limited Partnership (B2M LP) and an approximate 55% interest in Niagara Reinforcement Limited Partnership (NRLP). The Transmission segment also includes Hydro One Network’s approximate 48% minority interest in the East-West Tie Limited Partnership (EWT LP), which was acquired on March 4, 2025.

•The Distribution segment owns and operates Hydro One’s distribution system which delivers electricity to end customers and certain other municipal electricity distributors within Ontario. The distribution business consists of the distribution systems operated by Hydro One Inc.'s rate-regulated subsidiaries, Hydro One Networks and Hydro One Remote Communities Inc. (Hydro One Remotes).

•The Other segment consists principally of Hydro One’s telecommunications business, which provides telecommunications support for the Company’s transmission and distribution businesses, as well as certain corporate activities, and is not rate-regulated. The telecommunications business is carried out by Hydro One's wholly-owned subsidiary, Acronym Solutions Inc. (Acronym). In addition to supporting Hydro One's regulated business segments, Acronym offers a comprehensive suite of Information Communications Technology solutions. Hydro One's other segment also includes the deferred tax asset (DTA) which arose from the revaluation of the tax bases of Hydro One’s assets to fair market value when the Company transitioned from the provincial payments in lieu of tax regime to the federal tax regime at the time of the Company’s initial public offering in 2015. As this DTA is not required to be shared with ratepayers, the Company considers it to not be part of the regulated transmission and distribution segment assets and is included in the other segment. Furthermore, Hydro One's other segment also includes Aux Energy Inc., a wholly-owned subsidiary that provides energy solutions to commercial and industrial clients, and Ontario Charging Network LP (OCN LP), a wholly-owned subsidiary (2024 - a joint venture) that owns and operates electric vehicle fast charging stations across Ontario under the Ivy Charging Network brand.

Rate Setting

Transmission

On August 5, 2021 Hydro One Networks filed a custom Joint Rate Application (JRAP) for distribution and transmission revenue requirements for the 2023 to 2027 period. On November 29, 2022 the Ontario Energy Board (OEB) issued a Decision and Order (JRAP Decision) approving Hydro One Networks' transmission revenue requirement of $1,952 million for 2023, $2,073 million for 2024, $2,168 million for 2025, $2,277 million for 2026 and $2,362 million for 2027. Revenue requirements presented for 2024 to 2027 do not reflect the actual or expected updates resulting from the annual application process with the regulator to reflect OEB inflation factors.

On May 23, 2024, Hydro One Networks, on behalf of B2M LP, submitted B2M LP’s five-year transmission revenue requirement application for the 2025 to 2029 period. On November 21, 2024, the OEB issued a Decision and Order approving B2M LP’s five-year revenue requirement application, which includes a 2025 base revenue requirement of $38 million. Under the agreed-upon revenue requirement framework, there is no longer a requirement for B2M LP to file annual update applications with the OEB throughout the rate term, except for a one-time update in 2025, which the OEB approved in October 2025, setting the revenue requirements for 2026-2029.

On October 13, 2016, the OEB issued a Decision and Order for Hydro One Inc.’s Mergers, Amalgamations, Acquisitions and Divestitures of HOSSM, including the approval of a 10-year deferred rebasing period for the 2017 to 2026 period.

On July 12, 2024, Hydro One Networks, on behalf of CLLP, submitted CLLP’s five-year transmission revenue requirement application for the 2025 to 2029 period. On December 17, 2024, the OEB issued a Decision and Order approving CLLP’s revenue requirement application, which includes a 2025 base revenue requirement of $17 million, effective January 1, 2025. Under the agreed-upon revenue requirement framework, there is no longer a requirement for CLLP to file annual update applications with the OEB throughout the rate term, except for a one-time update in 2025, which the OEB approved in December 2025, setting the revenue requirements for 2026-2029.

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HYDRO ONE LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025 and 2024

On May 23, 2024, Hydro One Networks, on behalf of NRLP, submitted NRLP’s five-year transmission revenue requirement application for the 2025 to 2029 period. On November 21, 2024, the OEB issued a Decision and Order approving NRLP’s revenue requirement application, which includes a 2025 base revenue requirement of $9 million. Under the agreed-upon revenue requirement framework, there is no longer a requirement for NRLP to file annual update applications with the OEB throughout the rate term, except for a one-time update in 2025, which the OEB approved in October 2025, setting the revenue requirements for 2026-2029.

Distribution

On November 29, 2022 the OEB issued its JRAP Decision, approving Hydro One Networks' distribution revenue requirement of $1,727 million for 2023, $1,813 million for 2024, $1,886 million for 2025, $1,985 million for 2026 and $2,071 million for 2027. Revenue requirements presented for 2024 to 2027 do not reflect the actual or expected updates resulting from the annual application process with the regulator to reflect OEB inflation factors.

On August 31, 2022, Hydro One Remotes filed its distribution rate application for the 2023 to 2027 period. On March 2, 2023, the OEB approved Hydro One Remote’s 2023 revenue requirement of $128 million with a price cap escalator index for 2024 to 2027, and a 3.72% rate increase effective May 1, 2023. Revenue requirements for 2024 to 2027 will be updated per the annual application process with the regulator to reflect OEB inflation factors.

2.    SIGNIFICANT ACCOUNTING POLICIES

Basis of Consolidation and Presentation

These consolidated financial statements (Consolidated Financial Statements) include the accounts of the Company and its subsidiaries. Inter-company transactions and balances have been eliminated.

Basis of Accounting

These Consolidated Financial Statements are prepared and presented in accordance with United States (U.S.) generally accepted accounting principles (GAAP) and in Canadian dollars.

Use of Management Estimates

The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues, expenses, gains and losses during the reporting periods. Management evaluates these estimates on an ongoing basis based upon historical experience, current conditions, and assumptions believed to be reasonable at the time the assumptions are made, with any adjustments being recognized in results of operations in the period they arise. Significant estimates relate to unbilled revenues, regulatory assets and regulatory liabilities, pension benefits, and post-retirement and post-employment benefits. Actual results may differ significantly from these estimates.

Regulatory Accounting

The OEB has the general power to include or exclude revenues, costs, gains or losses in the rates of a specific period, resulting in a change in the timing of accounting recognition from that which would have been applied in an unregulated company. Such change in timing involves the application of rate-regulated accounting in accordance with Financial Accounting Standards Board (FASB) Accounting Standard Codification (Codification) Topic 980, Regulated Operations, within the Company's regulated business, giving rise to the recognition of regulatory assets and liabilities. The Company’s regulatory assets represent certain amounts receivable from electricity customers in a future period and costs that have been deferred for accounting purposes because it is probable that they will be recovered in future rates. In addition, the Company has recorded regulatory liabilities that generally represent amounts that are refundable to electricity customers in future rates. The Company continually assesses the likelihood of recovery of each of its regulatory assets and continues to believe that it is probable that the OEB will include its regulatory assets and regulatory liabilities in setting future rates. If, at some future date, the Company judges that it is no longer probable that the OEB will include a regulatory asset or regulatory liability in setting future rates, the respective carrying amount would be reflected in results of operations, prospectively from the date the Company’s assessment is made.

Cash and Cash Equivalents

Cash and cash equivalents include cash and short-term investments with an original maturity of three months or less.

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HYDRO ONE LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2025 and 2024

Revenue Recognition

Transmission revenues predominantly consist of transmission tariffs, which are collected through OEB-approved uniform transmission rates (UTRs) which are applied against the monthly peak demand for electricity across Hydro One's high-voltage network. OEB-approved UTRs are based on an approved revenue requirement that includes a rate of return. The transmission tariffs are designed to recover revenues necessary to support the Company's transmission system with sufficient capacity to accommodate the maximum expected demand which is influenced by weather and economic conditions. Transmission revenues are recognized as electricity is transmitted and delivered to customers.

Distribution revenues attributable to the delivery of electricity are based on OEB-approved distribution rates and are recognized on an accrual basis and include billed and unbilled revenues. Billed revenues are based on the amount of electricity delivered as measured from customer meters. At the end of each month, the amount of electricity delivered to customers since the date of the last billed meter reading is estimated, and the corresponding unbilled revenue is recorded. The unbilled revenue estimate is affected by energy consumption and changes in the composition of customer classes.

Revenues also include amounts related to sales of other services and equipment. Such revenue is recognized as services are rendered or as equipment is delivered. Revenues are recorded net of indirect taxes.

Accounts Receivable and Allowance for Doubtful Accounts

Billed accounts receivable are recorded at the invoiced amount, net of allowance for doubtful accounts. Unbilled accounts receivable are recorded at their estimated value, net of allowance for doubtful accounts. Overdue amounts related to regulated billings bear interest at OEB-approved rates. The allowance for doubtful accounts reflects the Company’s current lifetime expected credit losses (CECL) for all accounts receivable balances. The Company estimates the CECL by applying internally developed loss rates to all outstanding receivable balances by aging category on an undiscounted basis. Loss rates applied to the accounts receivable balances are based on historical overdue balances, customer payments and write-offs, which may be further supplemented from time to time to reflect management's best estimate of the loss. Accounts receivable are written-off against the allowance when they are deemed uncollectible. The allowance for doubtful accounts is affected by changes in volume, prices and economic conditions.

Noncontrolling interest

Noncontrolling interest represents the portion of equity ownership in subsidiaries that is not attributable to shareholders of Hydro One. Noncontrolling interest is initially recorded at fair value and subsequently the amount is adjusted for the proportionate share of net income or net loss and other comprehensive income (OCI) or other comprehensive loss (OCL) attributable to the noncontrolling interest and any dividends or distributions paid to the noncontrolling interest.

If a transaction results in the acquisition of all, or part, of a noncontrolling interest in a subsidiary, the acquisition of the noncontrolling interest is accounted for as an equity transaction. No gain or loss is recognized in consolidated net income or net loss or OCI or OCL as a result of changes in the noncontrolling interest, unless a change results in the loss of control by the Company.

Income Taxes

Income taxes are accounted for using the asset and liability method. Current income tax assets and current income tax liabilities are recognized based on the taxes refundable or payable on the current year’s taxable income. Current and deferred income taxes are computed based on the tax rates and tax laws enacted as at the balance sheet date. Tax benefits associated with income tax positions are recorded only when the more-likely-than-not recognition threshold is satisfied and are measured at the largest amount of benefit that has a greater than 50% likelihood of being realized upon settlement. Management evaluates each position based solely on the technical merits and facts and circumstances of the position, assuming the position will be examined by a taxing authority having full knowledge of all relevant information. Management judgment is required to determine recognition thresholds and the related amount of tax benefits to be recognized in the Consolidated Financial Statements. Management re-evaluates tax positions each period using new information about recognition or measurement as it becomes available.

Deferred Income Taxes

Deferred income tax assets and deferred income tax liabilities are recognized on all temporary differences between the tax bases and carrying amounts of assets and liabilities, including the carryforward of unused tax credits and tax losses to the extent that it is more-likely-than-not that these deductions, credits, and losses can be utilized. Deferred income tax assets and deferred income tax liabilities are measured at the tax rates that are expected to apply in the period when the asset is realized or the liability is settled, based on the tax rates and tax laws that have been enacted as at the balance sheet date.

Deferred income taxes associated with the Company’s regulated operations which are considered to be more-likely-than-not to be recovered or refunded in future regulated rates charged to customers are recognized as deferred income tax regulatory assets and deferred income tax regulatory liabilities with an offset to deferred income tax expense.

Investment tax credits are recorded as a reduction of the related expenses or income tax expense in the current or future period to the extent it is more likely than not that the credits can be utilized.

10

HYDRO ONE LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2025 and 2024

Management reassesses the deferred income tax assets at each balance sheet date and reduces the amount to the extent that it is more likely than not that the deferred income tax asset will not be realized. Previously unrecognized deferred income tax assets are reassessed at each balance sheet date and are recognized to the extent that it has become more likely than not that the tax benefit will be realized.

Property, Plant and Equipment

Property, plant and equipment is recorded at original cost, net of customer contributions, and any accumulated impairment losses. The cost of additions, including betterments and replacement asset components, is included on the consolidated balance sheets as property, plant and equipment.

The original cost of property, plant and equipment includes direct materials, direct labour (including employee benefits), contracted services, attributable capitalized financing costs, asset retirement costs, and direct and indirect overheads that are related to the capital project or program. Indirect overheads include a portion of corporate costs such as finance, treasury, human resources, and information technology. Overhead costs, including corporate functions and field services costs, are capitalized on a fully allocated basis.

Property, plant and equipment in service consists of transmission, distribution, communication, and administration and service assets, as well as land easements. Property, plant and equipment also includes future use assets, such as land, major components and spare parts, as well as capitalized project development costs associated with deferred capital projects.

Transmission

Transmission assets include assets used for the transmission of high-voltage electricity, such as transmission lines, support structures, foundations, insulators, connecting hardware and grounding systems, as well as assets used to step up the voltage of electricity from generating stations for transmission and to step down voltages for distribution, including transformers, circuit breakers and switches.

Distribution

Distribution assets include assets related to the distribution of low-voltage electricity, including lines, poles, switches, transformers, protective devices and metering systems.

Communication

Communication assets include fibre optic and microwave radio systems, optical ground wire, towers, telephone equipment and associated buildings.

Administration and Service

Administration and service assets include administrative buildings, personal computers, transport and work equipment, tools and other minor assets.

Easements

Easements include a statutory easement for the use of transmission corridor and related abutting lands pursuant to Part IX.1 of the Electricity Act, 1998 (Ontario) (Electricity Act), as well as other land rights for occupation.

Intangible Assets

Intangible assets separately acquired or internally developed are measured on initial recognition at cost, which comprises purchased software, direct labour (including employee benefits), consulting, engineering, overheads and attributable capitalized financing charges. Following initial recognition, intangible assets are carried at cost, net of any accumulated amortization and accumulated impairment losses. The Company’s intangible assets primarily represent major computer applications.

Capitalized Financing Costs

Capitalized financing costs represent interest costs attributable to the construction of property, plant and equipment or development of intangible assets. The financing cost of attributable borrowed funds is capitalized as part of the acquisition cost of such assets. The capitalized financing costs are a reduction of financing charges recognized in the consolidated statements of operations and comprehensive income. Capitalized financing costs are calculated using the Company’s weighted average effective cost of debt.

Construction and Development in Progress

Construction and development in progress consists of the capitalized cost of constructed assets that are not yet complete and which have not yet been placed in service.

11

HYDRO ONE LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2025 and 2024

Depreciation and Amortization

The cost of property, plant and equipment and intangible assets is depreciated or amortized on a straight-line basis based on the estimated remaining service life of each asset category, except for transport and work equipment, which is depreciated on a declining balance basis.

The Company periodically initiates an external independent review of its property, plant and equipment and intangible asset depreciation and amortization rates, as required by the OEB. Any changes arising from such a review are implemented on a remaining service life basis, consistent with their inclusion in electricity rates. The most recent reviews resulted in changes to rates effective January 1, 2023 for Hydro One Networks’ distribution and transmission businesses. A summary of average service lives and depreciation and amortization rates as at December 31, 2025 for the various classes of assets is included below:

			Average			Rate
			Service Life			Range			Average
Property, plant and equipment:
Transmission			57 years			1% - 3%			2		%
Distribution			48 years			1% - 8%			2		%
Communication			17 years			1% - 11%			6		%
Administration and service			28 years			1% - 20%			5		%
Intangible assets			11 years			8% - 10%			6		%

In accordance with group depreciation practices, the original cost of property, plant and equipment, or major components thereof, and intangible assets that are normally retired, is charged to accumulated depreciation, with no gain or loss being reflected in results of operations. Where a disposition of property, plant and equipment occurs through sale, a gain or loss is calculated based on proceeds and such gain or loss is included in depreciation expense.

Acquisitions and Goodwill

The Company accounts for business acquisitions using the acquisition method of accounting and, accordingly, the assets and liabilities of the acquired entities are primarily measured at their estimated fair value at the date of acquisition. Costs associated with pending acquisitions are expensed as incurred. Goodwill represents the cost of acquired companies that is in excess of the fair value of the net identifiable assets acquired at the acquisition date. Goodwill is not included in rate base.

Goodwill is evaluated for impairment on an annual basis, or more frequently if circumstances require. The Company performs a qualitative assessment to determine whether it is more likely than not that the fair value of the applicable reporting unit is greater than its carrying amount, no further testing is required. If the Company determines, as a result of its qualitative assessment, that it is more likely than not that the fair value of the applicable reporting unit is less than its carrying amount, a quantitative goodwill impairment assessment is performed. The quantitative assessment compares the fair value of the applicable reporting unit to its carrying amount, including goodwill. If the fair value of goodwill is less than the carrying amount, an impairment loss is recorded as a reduction to goodwill and as a charge to results of operations.

Based on the assessment performed as at September 30, 2025 and with no significant events since, the Company has concluded that goodwill was not impaired as at December 31, 2025.

Long-Lived Asset Impairment

When circumstances indicate the carrying value of long-lived assets may not be recoverable, the Company evaluates whether the carrying value of such assets, excluding goodwill, has been impaired. For such long-lived assets, the Company evaluates whether impairment may exist by estimating future undiscounted cash flows expected to result from the use and eventual disposition of the asset. When alternative courses of action to recover the carrying amount of a long-lived asset are under consideration, a probability-weighted approach is used to develop estimates of future undiscounted cash flows. If the carrying value of the long-lived asset is not recoverable based on the estimated future undiscounted cash flows, an impairment loss is recorded, measured as the excess of the carrying value of the asset over its fair value. As a result, the asset’s carrying value is adjusted to its estimated fair value.

Within its regulated business, the carrying costs of most of Hydro One’s long-lived assets are included in rate base where they earn an OEB-approved rate of return. Asset carrying values and the related return are recovered through approved rates. As a result, such assets are only tested for impairment in the event that the OEB disallows recovery, in whole or in part, or if such a disallowance is judged to be probable. Hydro One regularly monitors the assets of its unregulated subsidiary Acronym for indications of impairment.

Management assesses the fair value of such long-lived assets using commonly accepted techniques. Techniques used to determine fair value include, but are not limited to, the use of recent third-party comparable sales for reference and internally developed discounted cash flow analysis. Significant changes in market conditions, changes to the condition of an asset, or a change in management’s intent to utilize the asset are generally viewed by management as triggering events to reassess the cash flows related to these long-lived assets. As at December 31, 2025 and 2024, no asset impairment had been recorded for assets within either the Company’s regulated or unregulated businesses.

12

HYDRO ONE LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2025 and 2024

Costs of Arranging Debt Financing

For financial liabilities classified as other than held-for-trading, the Company defers the external transaction costs related to obtaining financing and presents such amounts net of related debt on the consolidated balance sheets. Deferred issuance costs are amortized over the contractual life of the related debt on an effective-interest basis and the amortization is included within financing charges in the consolidated statements of operations and comprehensive income. Transaction costs for items classified as held-for-trading are expensed immediately.

Financial Assets and Liabilities

All financial assets and liabilities are classified into one of the following five categories: held-to-maturity; loans and receivables; held-for-trading; other liabilities; or available-for-sale. Financial assets and liabilities classified as held-for-trading are measured at fair value. All other financial assets and liabilities are measured at amortized cost. Accounts receivable and amounts due from related parties are classified as loans and receivables. The Company considers the carrying amounts of accounts receivable and amounts due from related parties to be reasonable estimates of fair value because of the short time to maturity of these instruments. The Company estimates the CECL for all accounts receivable balances, which are recognized as adjustments to the allowance for doubtful accounts. Accounts receivable are written-off against the allowance when they are deemed uncollectible. All financial instrument transactions are recorded at trade date.

The Company determines the classification of its financial assets and liabilities at the date of initial recognition. The Company designates certain of its financial assets and liabilities to be held at fair value, when it is consistent with the Company’s risk management policy disclosed in Note 16 - Fair Value of Financial Instruments and Risk Management.

Derivative Instruments and Hedge Accounting

The Company closely monitors the risks associated with changes in interest rates on its operations and, where appropriate, uses various instruments to hedge these risks. Certain of these derivative instruments qualify for hedge accounting and are designated as accounting hedges, while others either do not qualify as hedges or have not been designated as hedges (hereinafter referred to as undesignated contracts) as they are part of economic hedging relationships.

The accounting guidance for derivative instruments requires the recognition of all derivative instruments not identified as meeting the normal purchase and sale exemption as either assets or liabilities recorded at fair value on the consolidated balance sheets. For derivative instruments that qualify for hedge accounting, the Company may elect to designate such derivative instruments as either cash flow hedges or fair value hedges. The Company offsets fair value amounts recognized on its consolidated balance sheets related to derivative instruments executed with the same counterparty under the same master netting agreement.

For derivative instruments that qualify for hedge accounting, and which are designated as cash flow hedges, any unrealized gain or loss, net of tax, is recorded as a component of accumulated OCI (AOCI) or accumulated OCL (AOCL). Amounts in AOCI or AOCL are reclassified to results of operations in the same period or periods during which the hedged transaction affects results of operations and presented in the same line item as the earnings effect of the hedged item. Any gains or losses on the derivative instrument that represent hedge components excluded from the assessment of effectiveness are recognized in the same line item of the consolidated statements of operations as the hedged item. For fair value hedges, changes in fair value of both the derivative instrument and the underlying hedged exposure are recognized in the consolidated statements of operations and comprehensive income (loss) in the current period. The gain or loss on the derivative instrument is included in the same line item as the offsetting gain or loss on the hedged item in the consolidated statements of operations and comprehensive income (loss). The changes in fair value of the undesignated derivative instruments are reflected in results of operations.

Embedded derivative instruments are separated from their host contracts and are carried at fair value on the consolidated balance sheets when: (a) the economic characteristics and risks of the embedded derivative are not clearly and closely related to the economic characteristics and risks of the host contract; (b) the hybrid instrument is not measured at fair value, with changes in fair value recognized in results of operations each period; and (c) the embedded derivative itself meets the definition of a derivative. The Company does not engage in derivative trading or speculative activities and had no embedded derivatives that required bifurcation as at December 31, 2025 or 2024.

Hydro One periodically develops hedging strategies taking into account risk management objectives. At the inception of a hedging relationship where the Company has elected to apply hedge accounting, Hydro One formally documents the relationship between the hedged item and the hedging instrument, the related risk management objective, the nature of the specific risk exposure being hedged, and the method for assessing the effectiveness of the hedging relationship. The Company also assesses, both at the inception of the hedge and on a quarterly basis, whether the hedging instruments are effective in offsetting changes in fair values or cash flows of the hedged items.

13

HYDRO ONE LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2025 and 2024

Employee Future Benefits

Employee future benefits provided by Hydro One include pension, post-retirement and post-employment benefits. The costs of the Company’s pension, post-retirement and post-employment benefit plans are recorded over the periods during which employees render service.

The Company recognizes the funded status of its defined benefit pension plan (Pension Plan) and its post-retirement and post-employment plans on its consolidated balance sheets and subsequently recognizes the changes in funded status at the end of each reporting year. Defined benefit pension, post-retirement and post-employment plans are considered to be underfunded when the projected benefit obligation (PBO) exceeds the fair value of the plan assets. Liabilities are recognized on the consolidated balance sheets for any net underfunded PBO. The net underfunded PBO may be disclosed as a current liability, long-term liability, or both. The current portion is the amount by which the actuarial present value of benefits included in the benefit obligation payable in the next 12 months exceeds the fair value of plan assets. If the fair value of plan assets exceeds the PBO of the plan, an asset is recognized equal to the net overfunded PBO. The post-retirement and post-employment benefit plans are unfunded because there are no related plan assets.

Hydro One recognizes its contributions to the defined contribution pension plan (DC Plan) as pension expense, with a portion being capitalized as part of labour costs included in capital expenditures. The expensed amount is included in operation, maintenance and administration (OM&A) costs in the consolidated statements of operations and comprehensive income.

Defined Benefit Pension

Defined benefit pension costs are recorded on an accrual basis for financial reporting purposes. Pension costs are actuarially determined using the projected benefit method prorated on service and are based on assumptions that reflect management’s best estimate of the effect of future events, including future compensation increases. Past service costs from plan amendments and all actuarial gains and losses are amortized on a straight-line basis over the expected average remaining service period of active employees in the plan, or over the estimated remaining life expectancy of inactive employees in the plan. Pension plan assets, consisting primarily of listed and unlisted equity securities, marketable and private debt, corporate and government debt securities as well as unlisted real estate and unlisted infrastructure investments, are recorded at fair value at the end of each year. Hydro One records a regulatory asset or regulatory liability equal to the net underfunded or overfunded PBO for its pension plan. Defined benefit pension costs are attributed to labour costs on a cash basis and a portion directly related to acquisition and development of capital assets is capitalized as part of the cost of property, plant and equipment and intangible assets. The remaining defined benefit pension costs are charged to results of operations (OM&A costs).

Post-retirement and Post-employment Benefits

Post-retirement and post-employment benefits are recorded and included in rates on an accrual basis. Costs are determined by independent actuaries using the projected benefit method prorated on service and based on assumptions that reflect management’s best estimates. For post-retirement benefits, past service costs from plan amendments are amortized to results of operations based on the expected average remaining service period.

For post-retirement benefits, all actuarial gains or actuarial losses are deferred using the “corridor” approach. The amount calculated above the “corridor” is amortized to results of operations on a straight-line basis over the expected average remaining service life of active employees in the plan or over the remaining life expectancy of inactive employees in the plan. The post-retirement benefit obligation is remeasured to its fair value at each year end, based on an annual actuarial report, with an offset to the associated regulatory account, to the extent of the remeasurement adjustment.

The actuarial gains and actuarial losses on post-employment obligations that are incurred during the year are recognized immediately to results of operations. The post-employment benefit obligation is remeasured to its fair value at each year end based on an annual actuarial report, with an offset to the associated regulatory account, to the extent of the remeasurement adjustment.

All post-retirement and post-employment benefit costs are attributed to labour costs and are either charged to results of operations (OM&A costs) or capitalized as part of the cost of property, plant and equipment and intangible assets (applies to the service cost component of benefit cost) and to regulatory assets for all other components of the benefit cost, consistent with their inclusion in OEB-approved rates.

Stock-Based Compensation

Share Grant Plans

Hydro One measures share grant plans based on fair value of share grants as estimated based on the grant date common share price. The costs are recognized in the financial statements using the graded-vesting attribution method for share grant plans that have both a performance condition and a service condition. The Company records a regulatory asset equal to the accrued costs of share grant plans recognized in each period. Costs are transferred from the regulatory asset to labour costs at the time the share grants vest and are recovered in rates. Forfeitures are recognized as they occur.

14

HYDRO ONE LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2025 and 2024

Deferred Share Unit (DSU) Plans

The Company records the liabilities associated with its Directors’ and Management DSU Plans at fair value at each reporting date until settlement, recognizing compensation expense over the vesting period on a straight-line basis. The fair value of the DSU liability is based on the Company’s common share closing price at the end of each reporting period.

Long-term Incentive Plan (LTIP)

The Company measures the awards issued under its LTIP at fair value based on the grant date common share price. The fair value of liability-classified awards is based on the Company’s common share closing price at the end of each reporting period. The related compensation expense is recognized over the vesting period on a straight-line basis. Forfeitures are recognized as they occur.

Loss Contingencies

Hydro One is involved in certain legal and environmental matters that arise in the normal course of business. In the preparation of its Consolidated Financial Statements, management makes judgments regarding the future outcome of contingent events and records a loss for a contingency based on its best estimate when it is determined that such loss is probable and the amount of the loss can be reasonably estimated. Where the loss amount is recoverable in future rates, a regulatory asset is also recorded. When a range estimate for the probable loss exists and no amount within the range is a better estimate than any other amount, the Company records a loss at the minimum amount within the range.

Management regularly reviews current information available to determine whether recorded provisions should be adjusted and whether new provisions are required. Estimating probable losses may require analysis of multiple forecasts and scenarios that often depend on judgments about potential actions by third parties, such as federal, provincial and local courts or regulators. Contingent liabilities are often resolved over long periods of time. Amounts recorded in the Consolidated Financial Statements may differ from the actual outcome once the contingency is resolved. Such differences could have a material impact on future results of operations, financial position and cash flows of the Company.

Provisions are based upon current estimates and are subject to greater uncertainty where the projection period is lengthy. A significant upward or downward trend in the number of claims filed, the nature of the alleged injuries, and the average cost of resolving each claim could change the estimated provision, as could any substantial adverse or favourable verdict at trial. A federal or provincial legislative outcome or structured settlement could also change the estimated liability. Legal fees are expensed as incurred.

Environmental Liabilities

Environmental liabilities are recorded in respect of past contamination when it is determined that future environmental remediation expenditures are probable under existing statute or regulation and the amount of the future expenditures can be reasonably estimated. Hydro One records a liability for the estimated future expenditures associated with contaminated land assessment and remediation (LAR) and for the phase-out and destruction of polychlorinated biphenyl (PCB)-contaminated mineral oil removed from electrical equipment, based on the present value of these estimated future expenditures. To the extent that the Company anticipates that the future expenditures will continue to be recoverable in future rates, an offsetting regulatory asset has been recorded to reflect the anticipated amount of future recovery of these environmental expenditures from customers. Hydro One reviews its estimates of future environmental expenditures annually, or more frequently if there are indications that circumstances have changed. Estimate changes are accounted for prospectively.

Asset Retirement Obligations

Asset retirement obligations are recorded for legal obligations associated with the future removal and disposal of long-lived assets. Such obligations may result from the acquisition, construction, development and/or normal use of the asset. Conditional asset retirement obligations are recorded when there is a legal obligation to perform a future asset retirement activity but where the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the Company. In such a case, the obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. This uncertainty is incorporated in the fair value measurement of the obligation.

When recording an asset retirement obligation, the present value of the estimated future expenditures required to complete the asset retirement activity is recorded in the period in which the obligation is incurred, if a reasonable estimate can be made. In general, the present value of the estimated future expenditures is added to the carrying amount of the associated asset and the resulting asset retirement cost is depreciated over the estimated useful life of the asset. The present value is    determined with a discount rate that equates to the Company’s credit-adjusted risk-free rate. Where an asset is no longer in service when an asset retirement obligation is recorded, the asset retirement cost is recorded in results of operations.

Leases

At the commencement date of a lease, the minimum lease payments are discounted and recognized as a lease obligation. Discount rates used correspond to the Company's incremental borrowing rates. Renewal options are assessed for their likelihood of being exercised and are included in the measurement of the lease obligation when it is reasonably certain they will be

15

HYDRO ONE LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2025 and 2024

exercised. The Company does not recognize leases with a term of less than 12 months. A corresponding Right-of-Use (ROU) asset is recognized at the commencement date of a lease. The ROU asset is measured as the lease obligation adjusted for any lease payments made and/or any lease incentives and initial direct costs incurred. ROU assets are included in other long-term assets, and corresponding lease obligations are included in other current liabilities and other long-term liabilities on the consolidated balance sheets.

The Company’s lease portfolio consists primarily of operating leases; finance leases are not material and, when applicable, may be fully prepaid at commencement.

Subsequent to the commencement date, the lease expense recognized at each reporting period is the total remaining lease payments over the remaining lease term. Lease obligations are measured as the present value of the remaining unpaid lease payments using the discount rate established at commencement date. The amortization of the ROU assets is calculated as the difference between the lease expense and the accretion of interest, which is calculated using the effective interest method. Lease modifications and impairments are assessed at each reporting period to assess the need for a remeasurement of the lease obligations or ROU assets.

Equity Method Investments

The Company accounts for its investments in entities over which it has significant influence but not a controlling interest using the equity method of accounting. Significant influence is generally presumed to exist when the Company owns 20% to 50% of the voting stock of the investee, but can also exist when the Company owns less than 20% if it has the ability to exercise significant influence through other means. Under this method, the investment is initially recorded at cost and subsequently adjusted to recognize the Company’s share of the earnings or losses of the investee, as well as any distributions received from the investee.

3.    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

Guidance

Date issued

Description

ASU Effective Date

Impact on Hydro One

ASU 2024-02

March 2024

The amendments contain modifications to the codification that remove various concept statements which may be extraneous and not required to understand or apply the guidance or references used in prior statements to provide guidance in certain topical areas.

Fiscal years beginning after December 15, 2024.

No impact upon adoption

ASU 2023-09

December 2023

The amendments address investor requests for more transparency about income tax information through improvements to income tax disclosures primarily related to the rate reconciliation and income taxes paid information.

Annual periods beginning after December 15, 2024.

Adoption of the standard does not materially affect Hydro One’s income tax disclosures.

16

HYDRO ONE LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2025 and 2024

Recently Issued Accounting Guidance Not Yet Adopted

Guidance

Date issued

Description

ASU Effective Date

Impact on Hydro One

ASU 2023-06

October 2023

The 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 2024

The 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 2025-03

May 2025

The 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 2025-05

July 2025

The 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

ASU 2025-06

September 2025

The 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 periods beginning after December 15, 2027.

Under assessment

ASU 2025-09

November 2025

The 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 2025-10

December 2025

The 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 2025-11

December 2025

The 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 2025-12

December 2025

The 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

17

HYDRO ONE LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2025 and 2024

4.    DEPRECIATION, AMORTIZATION AND ASSET REMOVAL COSTS

Year ended December 31 (millions of dollars)									2025			2024
Depreciation of property, plant and equipment									874			828
Amortization of intangible assets									89			81
Amortization of regulatory assets									3			11
Depreciation and amortization									966			920
Asset removal costs									145			146
									1,111			1,066

5. FINANCING CHARGES

Year ended December 31 (millions of dollars)									2025			2024
Interest on long-term debt									736			674
Interest on regulatory accounts									24			25
Interest on short-term notes									23			21
Realized loss (gain) on cash flow hedges (interest-rate swap agreements) (Note 16)									4			(4)
Other									19			18
Less: Interest capitalized on construction and development in progress									(110)			(89)
Interest earned on cash and cash equivalents									(17)			(24)
									679			621

6.    INCOME TAXES

As a rate regulated utility company, the Company recovers income taxes from its ratepayers based on estimated current income tax expense in respect of its regulated business. The amounts of deferred income taxes related to regulated operations which are considered to be more likely-than-not to be recoverable from, or refundable to, ratepayers in future periods are recognized as deferred income tax regulatory assets or deferred income tax regulatory liabilities, with an offset to deferred income tax recovery or deferred income tax expense, respectively. The Company’s consolidated income tax expense or income tax recovery for the period includes all current and deferred income tax expenses for the period net of the regulated accounting offset to deferred income tax expense arising from temporary differences to be recovered from, or refunded to, customers in future rates. Thus, the Company’s income tax expense or income tax recovery differs from the amount that would have been recorded using the statutory income tax rate. As the Company operates in Ontario, it is subject to the combined Canadian federal and Ontario statutory rates of 26.5%.

The reconciliation between the statutory and the effective tax rates is provided as follows:

			2025						2024
Year ended December 31			(millions of dollars)			(percentage)			(millions of dollars)			(percentage)
Income before income tax expense			1,568						1,346
Income tax expense at statutory rate of 26.5% (2024 - 26.5%)			416			26.5		%	357			26.5		%
Increase (decrease) resulting from:
Net temporary differences recoverable in future rates charged to customers:
Capital cost allowance in excess of depreciation and amortization			(106)			(6.8)		%	(83)			(6.2)		%
Overheads capitalized for accounting but deducted for tax purposes			(54)			(3.4)		%	(51)			(3.8)		%
Interest capitalized for accounting but deducted for tax purposes			(29)			(1.8)		%	(23)			(1.7)		%
Pension and post-retirement benefit contributions in excess of pension expense			(5)			(0.3)		%	(10)			(0.7)		%
Non-refundable tax credit			(5)			(0.3)		%	(3)			(0.2)		%
Environmental expenditures			(1)			(0.1)		%	(3)			(0.2)		%
Other			1			0.1		%	(1)			(0.1)		%
Net temporary differences attributable to regulated business			(199)			(12.7)		%	(174)			(12.9)		%
Net permanent differences			2			0.1		%	(2)			(0.1)		%
Total income tax expense			219			14.0		%	181			13.4		%

The major components of income tax expense are as follows:

Year ended December 31 (millions of dollars)			2025			2024
Current income tax expense			144			38
Deferred income tax expense			75			143
Total income tax expense			219			181

18

HYDRO ONE LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2025 and 2024

Deferred Income Tax Assets and Liabilities

Deferred income tax assets and deferred income tax liabilities reflect the future income tax consequences attributable to temporary differences between the tax bases and the financial statement carrying amounts of the assets and liabilities including the carry forward amounts of tax losses and tax credits. Deferred income tax assets and deferred income tax liabilities attributable to the Company’s regulated business are recognized with a corresponding offset in deferred income tax regulatory assets and deferred income tax liabilities to reflect the anticipated recovery or repayment of these balances in the future electricity rates. As at December 31, 2025 and 2024, deferred income tax assets and deferred income tax liabilities consisted of the following:

As at December 31 (millions of dollars)			2025			2024
Deferred income tax assets
Post-retirement and post-employment benefits expense in excess of cash payments			616			585
Regulatory assets and liabilities			491			449
Non-capital losses			91			105
Non-depreciable capital property			255			255
Tax credit carryforwards			211			245
Investment in subsidiaries			114			113
Capital losses			27			19
Environmental expenditures			15			16
Other			3			11
			1,823			1,798
Less: valuation allowance			(399)			(394)
Total deferred income tax assets			1,424			1,404
Deferred income tax liabilities
Capital cost allowance in excess of depreciation and amortization			2,874			2,494
Pension assets			214			235
Total deferred income tax liabilities			3,088			2,729
Net deferred income tax liabilities			(1,664)			(1,325)

The net deferred income tax liabilities are presented on the consolidated balance sheets as follows:

As at December 31 (millions of dollars)			2025			2024
Long-term:
Deferred income tax assets			135			127
Deferred income tax liabilities			(1,799)			(1,452)
Net deferred income tax liabilities			(1,664)			(1,325)

The valuation allowance for deferred income tax assets as at December 31, 2025 was $399 million (2024 - $394 million). The valuation allowance primarily relates to temporary differences for non-depreciable assets, investments in subsidiaries and capital losses carried forward.

As at December 31, 2025 and 2024, the Company had non-capital losses carried forward available to reduce future years’ taxable income, which expire as follows:

Year of expiry (millions of dollars)			2025			2024
2036			1			1
2037			4			41
2038			90			92
2039			15			77
2040			9			14
2041			20			22
2042			29			38
2043			32			38
2044			59			51
2045			68			—
Total losses			327			374

19

HYDRO ONE LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2025 and 2024

7.    ACCOUNTS RECEIVABLE

As at December 31 (millions of dollars)			2025			2024
Accounts receivable - billed			467			433
Accounts receivable - unbilled			673			539
Accounts receivable, gross			1,140			972
Allowance for doubtful accounts			(57)			(61)
Accounts receivable, net			1,083			911

The following table shows the movements in the allowance for doubtful accounts for the years ended December 31, 2025 and 2024:

As at December 31 (millions of dollars)						2025			2024
Allowance for doubtful accounts – beginning						(61)			(57)
Write-offs						23			18
Additions to allowance for doubtful accounts						(19)			(22)
Allowance for doubtful accounts – ending						(57)			(61)

8.    OTHER CURRENT ASSETS

As at December 31 (millions of dollars)			2025			2024
Prepaid expenses and other assets			92			94
Materials and supplies			31			29
Regulatory assets (Note 11)			10			42
			133			165

9.    PROPERTY, PLANT AND EQUIPMENT

As at December 31, 2025 (millions of dollars)			Property, Plant  and Equipment			Accumulated Depreciation			Construction in Progress			Total
Transmission			23,618			7,437			2,191			18,372
Distribution			15,338			5,053			304			10,589
Communication			1,539			1,327			57			269
Administration and service			2,578			1,101			46			1,523
Easements			821			124			—			697
			43,894			15,042			2,598			31,450
As at December 31, 2024 (millions of dollars)			Property, Plant  and Equipment			Accumulated Depreciation			Construction in Progress			Total
Transmission			22,359			7,100			1,616			16,875
Distribution			14,335			4,813			318			9,840
Communication			1,511			1,242			45			314
Administration and service			2,382			1,063			134			1,453
Easements			733			122			—			611
			41,320			14,340			2,113			29,093

Financing charges capitalized on property, plant and equipment under construction were $107 million in 2025 (2024 - $85 million).

20

HYDRO ONE LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2025 and 2024

10.    INTANGIBLE ASSETS

As at December 31, 2025 (millions of dollars)			Intangible Assets			Accumulated Amortization			Development in Progress			Total
Computer applications software			1,585			960			29			654
Other			5			5			—			—
			1,590			965			29			654
As at December 31, 2024 (millions of dollars)			Intangible Assets			Accumulated Amortization			Development in Progress			Total
Computer applications software			1,481			872			51			660
Other			6			5			—			1
			1,487			877			51			661

Financing charges capitalized on intangible assets under development were $3 million in 2025 (2024 - $4 million). The estimated annual amortization expense for intangible assets is as follows: 2026 - $91 million; 2027 - $88 million; 2028 - $83 million; 2029 - $74 million; and 2030 - $66 million.

11.    REGULATORY ASSETS AND LIABILITIES

Regulatory assets and liabilities arise as a result of the rate-setting process. Hydro One has recorded the following regulatory assets and liabilities:

As at December 31 (millions of dollars)			2025			2024
Regulatory assets:
Deferred income tax regulatory asset			3,549			3,263
Broadband deferral			73			48
Post-retirement and post-employment benefits - non-service cost			49			72
Environmental			43			44
Getting Ontario Connected Act variance			39			24
Distribution rate riders			26			—
Incremental cloud computing implementation costs deferral			20			10
Stock-based compensation			18			24
Rural and remote rate protection (RRRP) variance			—			18
Other			50			42
Total regulatory assets			3,867			3,545
Less: current portion			(10)			(42)
			3,857			3,503
Regulatory liabilities:
Pension benefit regulatory liability			610			647
Post-retirement and post-employment benefits			336			376
Earnings sharing mechanism (ESM) deferral			310			150
Retail settlement variance account (RSVA)			242			157
External revenue variance			75			31
Capitalized overhead tax variance			50			38
Other post-employment benefits (OPEB) asymmetrical carrying charge variance			49			33
Asset removal costs cumulative variance			48			26
Tax rule changes variance			36			34
Pension cost differential variance			30			21
Advanced Metering Infrastructure (AMI) 2.0 variance			29			7
Deferred income tax regulatory liability			9			4
Distribution rate riders			—			45
Other			27			29
Total regulatory liabilities			1,851			1,598
Less: current portion			(230)			(122)
			1,621			1,476

21

HYDRO ONE LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2025 and 2024

Deferred Income Tax Regulatory Asset and Liability

Deferred income taxes are recognized on temporary differences between the carrying amount of assets and liabilities in the financial statements and the corresponding tax bases used in the computation of taxable income. The Company has recognized regulatory assets and regulatory liabilities that correspond to deferred income taxes that flow through the rate-setting process. In the absence of rate-regulated accounting, the Company’s income tax expense would have been recognized using the liability method and there would be no regulatory accounts established for income taxes to be recovered through future rates.

Broadband Deferral

The Company recognizes the incremental costs and incremental revenues attributable to carrying out activities pertaining to designated broadband projects as defined under Building Broadband Faster Act (Ontario) in this generic deferral account.

Post-Retirement and Post-Employment Benefits - Non-Service Cost

Hydro One has recorded a regulatory asset relating to the future recovery of its post-retirement and post-employment benefits other than service costs. The regulatory asset includes the applicable tax impact to reflect taxes payable. Prior to adoption of ASU 2017-07 in 2018, these amounts were capitalized to property, plant and equipment and intangible assets. In 2018 and 2019, the OEB approved the regulatory asset for Hydro One Networks’ transmission business and distribution business, respectively. As part of Hydro One Networks' 2020 to 2022 Transmission Decision, the OEB concluded that the non-service cost component of Hydro One's OPEB costs shall be recognized as OM&A for both its transmission and distribution businesses. Furthermore, Hydro One Networks Distribution continued to record the non-service cost component of OPEBs in this account until the end of 2022. As part of the JRAP Decision received in November 2022, the OEB approved the disposition of Hydro One Networks' transmission and distribution account balances as at December 31, 2020, including accrued interest, which were recovered from ratepayers over a one-year period ending December 31, 2023, and a three-year period ended December 31, 2025, respectively.

Environmental

Hydro One records a liability for the estimated future expenditures required to remediate environmental contamination. A regulatory asset is recognized to the extent management considers it to be probable that environmental expenditures will be recovered in the future through the rate-setting process. For the year ended December 31, 2025, the Company has recorded a portion of the liability as a regulatory asset. In 2025, the revaluation adjustment increased the environmental regulatory asset by $2 million (2024 - $2 million) to reflect changes in the recoverable portion of the Company’s PCB and LAR environmental liabilities. The environmental regulatory asset is amortized to results of operations based on the pattern of actual expenditures incurred and charged to environmental liabilities. The OEB has the discretion to examine and assess the prudence and the timing of recovery of all of Hydro One’s actual environmental expenditures.

Getting Ontario Connected Act Variance

On October 31, 2023, the OEB issued its Decision and Order approving the establishment of a generic sector-wide variance account, effective April 1, 2023. The account was established to record incremental costs of locating underground infrastructure resulting from the implementation of Provincial legislation: Bill 93, Getting Ontario Connected Act, 2022.

Distribution Rate Riders

As part of the JRAP Decision, the OEB approved the disposition of certain deferral and variance account balances as at December 31, 2020, including accrued interest, which were accumulated in distribution rate riders. The amounts were disposed of over a three-year period that ended December 31, 2025. The balance in the account is mostly comprised of excess returns to be collected from ratepayers in a future rate application.

Incremental cloud computing implementation costs deferral

On November 2, 2023, the OEB issued an Accounting Order approving the establishment of a generic sector-wide deferral account, effective December 1, 2023. The account was established to record incremental cloud computing implementation costs.

Stock-based Compensation

The Company recognizes costs associated with share grant plans as a regulatory asset as management considers it probable that share grant plans' costs will be recovered in the future through the rate-setting process. Share grant costs are transferred to labour costs at the time they vest and are issued, and are recovered in rates in accordance with recovery of these labour costs.

RRRP Variance

Hydro One Remotes receives RRRP amounts from the Independent Electricity System Operator (IESO). As at December 31, 2025, the Company recognized a regulatory liability representing the amounts over-collected to achieve breakeven net income, as regulated under the cost recovery model. In both 2025 and 2024, RRRP amounts received were higher than amounts required to achieve breakeven net income, and as such, the regulatory asset decreased by $24 million and $12 million, in 2025 and 2024, respectively.

22

HYDRO ONE LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2025 and 2024

Pension Benefit Regulatory Liability

In accordance with OEB rate orders, pension costs are recovered on a cash basis as employer contributions are paid to the pension fund in accordance with the Pension Benefits Act (Ontario). The Company recognizes the net unfunded or funded status of pension obligations on the consolidated balance sheets with an offset to the associated regulatory asset or regulatory liability. The pension benefit obligation is remeasured to the present value of the actuarially determined benefit obligation at each year end based on an annual actuarial report, with an offset to the associated regulatory asset or regulatory liability, to the extent of the remeasurement adjustment.

Post-Retirement and Post-Employment Benefits

In accordance with OEB rate orders, post-retirement and post-employment benefits costs are recovered on an accrual basis. The Company recognizes the net unfunded or funded status of post-retirement and post-employment obligations on the consolidated balance sheets with an incremental offset to the associated regulatory asset or regulatory liability, as the case may be. A regulatory asset or regulatory liability is recognized because management considers it to be probable that post-retirement and post-employment benefit costs will be recovered or returned in the future through the rate-setting process. The post-retirement and post-employment benefit obligation is remeasured to the present value of the actuarially determined benefit obligation at each year end based on an annual actuarial report, with an offset to the associated regulatory asset or regulatory liability, as the case may be, to the extent of the remeasurement adjustment.

ESM Deferral

In March 2019, the OEB approved the establishment of an ESM deferral account for Hydro One Networks' distribution segment to record over-earnings including tax impacts. Under this mechanism, Hydro One shares 50% of regulated earnings that exceed the OEB-approved regulatory return-on-equity (ROE) by more than 100 basis points with distribution ratepayers. A similar account was also approved for B2M LP in January 2020, Hydro One Networks’ transmission segment and NRLP in April 2020, and CLLP in December 2024. HOSSM's account was approved as part of the acquisition decision in October 2016 and became effective in 2022, with a 300 basis points threshold applied. The balance in the account as at December 31, 2025 mostly relates to Hydro One Networks’ distribution and transmission businesses. As part of the JRAP Decision received in November 2022, the OEB approved the disposition of Hydro One Networks' distribution business' balance as at December 31, 2020, including accrued interest, over a three-year period that ended December 31, 2025. The OEB also approved the disposition of the ESM account balances as at December 31, 2024 in Hydro One Networks’ distribution and transmission businesses, B2M LP, NRLP, and HOSSM’s 2026 rates application on a final basis.

RSVA

Hydro One has deferred certain retail settlement variance amounts under the provisions of Article 490 of the OEB’s Accounting Procedures Handbook. The RSVA account tracks the difference between the cost of power purchased from the IESO and the cost of power recovered from ratepayers. As part of the JRAP Decision received in November 2022, the OEB approved the disposition of Hydro One Networks' distribution business' balance as at December 31, 2020, including accrued interest, over a three-year period that ended December 31, 2025. In December 2024, as part of the Decision and Order on 2025 distribution rates, the OEB approved, on an interim basis, the disposition of certain RSVA balances as at December 31, 2023, including accrued interest, over a one-year period that ended December 31, 2025. This disposition became final upon receipt of the Decision and Order on 2026 distribution rates issued in December 2025. The OEB also approved disposition of certain RSVA balances as at December 31, 2025, including accrued interest, over a one-year period ending December 31, 2026 on both an interim and final basis.

External Revenue Variance

The external revenue variance account balance reflects the difference between Hydro One Networks' transmission business' actual export service revenue and external revenues from secondary land use, and the OEB-approved amounts. The account also records the difference between actual net external station maintenance, engineering and construction services revenue, and other external revenue, and the OEB-approved amounts.

Capitalized Overhead Tax Variance

As part of the JRAP Decision, the OEB approved the establishment of a capitalized overhead tax variance account to capture the difference between the capitalized overheads deducted in calculating the regulatory tax expense included in rates and the actual capitalized overhead costs deducted in Hydro One's tax returns for Hydro One Networks' transmission and distribution businesses for the 2016 to 2027 period. Variance amounts are recognized at the earlier of (i) when the tax year has been audited by the Canada Revenue Agency or (ii) when the taxation year is statute barred.

OPEB Asymmetrical Carrying Charge Variance Account

On September 14, 2017, the OEB issued its Report of the Board: Regulatory Treatment of Pension and OPEB Costs that allowed rate-regulated utilities to track the difference between their pension and OPEB costs calculated under the accrual method and the cash payment method, effective January 1, 2018, and record the carrying charges associated with the balance on an asymmetrical basis. As part of the JRAP Decision received in November 2022, the OEB approved the disposition of Hydro

23

HYDRO ONE LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2025 and 2024

One Networks’ transmission and distribution account balances as at December 31, 2020, including accrued interest, which were returned to ratepayers over a one-year period ended December 31, 2023, and a three-year period ended December 31, 2025, respectively. As part of the same decision, the OEB approved the continuance of this account for Hydro One Networks’ transmission business and the establishment of this account for Hydro One Networks’ distribution business for 2023 to 2027.

Asset Removal Costs Cumulative Variance

In April 2020, the OEB approved the establishment of an asset removal costs cumulative variance account for Hydro One Networks' transmission business to record the difference between the revenue requirement associated with forecast asset removal costs included in depreciation expense and actual asset removal costs. This account is asymmetrical to the benefit of ratepayers on a cumulative basis. As part of the JRAP Decision received in November 2022, the OEB approved the continuance of this account for Hydro One Networks’ transmission business and the establishment of this account for Hydro One Networks’ distribution business for the 2023 to 2027 period.

Tax Rule Changes Variance

The 2019 federal and Ontario budgets (Budgets) provided certain time-limited investment incentives permitting Hydro One to deduct accelerated capital cost allowance of up to three times the first-year rate for capital investments acquired after November 20, 2018 and placed in-service before January 1, 2028 (Accelerated Depreciation). Following the enactment of the Budget measures in the second quarter of 2019, the OEB directed all Ontario regulated utilities including Hydro One to track the full revenue impact of the tax benefits related to the Accelerated Depreciation rules to ratepayers. The tax benefit to be returned to ratepayers in the future gave rise to a regulatory liability and resulted in a decrease in revenues as current rates do not include the benefit of the Accelerated Depreciation; therefore, the revenue subject to refund cannot be recognized. As part of the JRAP Decision received in November 2022, the OEB approved the disposition of Hydro One Networks' transmission and distribution account balances as at December 31, 2020, including accrued interest, which were returned to ratepayers over a one-year period ended December 31, 2023, and a three-year period ended December 31, 2025, respectively.

Pension Cost Differential

Variances between the OM&A pension cost recognized and the cost embedded in rates as part of the rate-setting process for Hydro One Networks' transmission and distribution businesses are recognized as a regulatory asset or regulatory liability, as the case may be. As part of the JRAP Decision received in November 2022, the OEB approved the disposition of Hydro One Networks' transmission and distribution account balances as at December 31, 2020, including accrued interest, which were returned to ratepayers over a one-year period ended December 31, 2023 and a three-year period ended December 31, 2025, respectively.

AMI 2.0 Variance

As part of the JRAP Decision, the OEB approved the establishment of the AMI 2.0 variance account. The account records the difference in revenue requirement impact including tax, if any, between the planned in-service additions included in the forecasted costs of the AMI 2.0 program over the 2023-2027 period and the actual in-service additions achieved as part of the AMI 2.0 program over the 2023-2027 period. The account is asymmetrical to the benefit of ratepayers.

12.    OTHER LONG-TERM ASSETS

As at December 31 (millions of dollars)			2025			2024
Deferred pension assets (Note 18)			610			647
Investments in associates1			302			46
Right-of-Use assets (Note 21)			47			55
Other long-term assets			64			60
			1,023			808

1 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.

24

HYDRO ONE LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2025 and 2024

13.    ACCOUNTS PAYABLE AND OTHER CURRENT LIABILITIES

As at December 31 (millions of dollars)			2025			2024
Accrued liabilities			944			794
Accounts payable			371			348
Unearned revenue			313			336
Regulatory liabilities (Note 11)			230			122
Accrued interest			203			180
Lease obligations (Note 21)			14			14
Environmental liabilities			7			11
Derivative liabilities (Note 16)			4			4
			2,086			1,809

14.    OTHER LONG-TERM LIABILITIES

As at December 31 (millions of dollars)			2025			2024
Post-retirement and post-employment benefit liability (Note 18)			1,672			1,590
Asset retirement obligations (Note 20)			43			38
Environmental liabilities (Note 19)			37			36
Lease obligations (Note 21)			29			41
Derivative liabilities (Note 16)			—			3
Other long-term liabilities			42			43
			1,823			1,751

15.    DEBT AND CREDIT AGREEMENTS

Short-Term Notes and Credit Facilities

Hydro One meets its short-term liquidity requirements in part through the issuance of commercial paper under Hydro One Inc.’s commercial paper program which has a maximum authorized amount of $2,300 million. These short-term notes are denominated in Canadian dollars with varying maturities of up to 365 days. The commercial paper program is supported by Hydro One Inc.’s revolving standby credit facilities totalling $3,050 million.

As at December 31, 2025, Hydro One’s consolidated committed, unsecured, and revolving credit facilities (Operating Credit Facilities) consisted of the following:

(millions of dollars)			Maturity			Total Amount			Amount Drawn
Hydro One Inc.
Revolving standby credit facilities1,2			June 2030			3,050			—
Hydro One
Five-year senior, revolving term credit facility2			June 2030			250			—
Total						3,300			—

1 On June 1, 2024, Hydro One Inc. increased the committed amount under the Operating Credit Facilities by $750 million.

2 On June 1, 2025, the maturity dates for the Operating Credit Facilities were extended from June 2029 to June 2030.

The Company may use the Operating Credit Facilities for working capital and general corporate purposes. If used, interest on the Operating Credit Facilities would apply based on Canadian benchmark rates. The Operating Credit Facilities include a pricing adjustment which can increase or decrease Hydro One’s cost of funding based on its performance on certain sustainability performance measures, which are related to Hydro One's sustainability goals. The obligation of each lender to extend credit under its credit facility is subject to various conditions including that no event of default has occurred or would result from such credit extension.

Subsidiary Debt Guarantee

Hydro One Holdings Limited (HOHL) is an indirect wholly-owned subsidiary of Hydro One that may offer and sell debt securities. Any debt securities issued by HOHL are fully and unconditionally guaranteed by the Company. As at December 31, 2025 and 2024, no debt securities have been issued by HOHL.

25

HYDRO ONE LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2025 and 2024

Long-Term Debt

The following table presents long-term debt outstanding as at December 31, 2025 and 2024:

As at December 31 (millions of dollars)			2025			2024
1.76% Series 45 notes due 2025			—			400
2.97% Series 40 notes due 2025			—			350
5.54% Series 57 notes due 20251			—			400
2.77% Series 35 notes due 2026			500			500
Floating-rate Series 56 notes due 20262			425			425
4.91% Series 52 notes due 2028			750			750
3.02% Series 43 notes due 2029			550			550
3.93% Series 53 notes due 2029			550			550
2.16% Series 46 notes due 2030			400			400
7.35% Debentures due 2030			400			400
1.69% Series 49 notes due 2031			400			400
2.23% Series 50 notes due 2031			450			450
6.93% Series 2 notes due 2032			500			500
3.94% Series 61 notes due 2032			450			—
4.16% Series 54 notes due 2033			450			450
3.90% Series 64 notes due 2033			1,200			—
6.35% Series 4 notes due 2034			385			385
4.39% Series 59 notes due 2034			550			550
4.25% Series 60 notes due 2035			1,075			1,075
4.30% Series 62 notes due 2035			300			—
5.36% Series 9 notes due 2036			600			600
4.89% Series 12 notes due 2037			400			400
6.03% Series 17 notes due 2039			300			300
5.49% Series 18 notes due 2040			500			500
4.39% Series 23 notes due 2041			300			300
6.59% Series 5 notes due 2043			315			315
4.59% Series 29 notes due 2043			435			435
4.17% Series 32 notes due 2044			350			350
5.00% Series 11 notes due 2046			325			325
3.91% Series 36 notes due 2046			350			350
3.72% Series 38 notes due 2047			450			450
3.63% Series 41 notes due 2049			750			750
2.71% Series 47 notes due 2050			500			500
3.64% Series 44 notes due 2050			250			250
3.10% Series 51 notes due 2051			450			450
4.00% Series 24 notes due 2051			225			225
4.46% Series 55 notes due 2053			675			675
4.85% Series 58 notes due 2054			1,000			1,000
4.95% Series 63 notes due 2055			350			—
4.80% Series 65 notes due 2056			400			—
3.79% Series 26 notes due 2062			310			310
4.29% Series 30 notes due 2064			50			50
Hydro One Inc. long-term debt (a)			18,620			17,070
1.41% Series 2020-1 notes due 2027			425			425
Hydro One long-term debt (b)			425			425
			19,045			17,495
Add: Net unamortized debt premiums			39			41
Add: Realized mark-to-market gain1			—			3
Less: Unamortized deferred debt issuance costs			(67)			(60)
Total long-term debt			19,017			17,479

1 In October 2023, Hydro One Inc. entered into a $400 million fixed-to-floating interest-rate swap agreement to convert the $400 million Medium Term Note (MTN) Series 57 notes matured October 20, 2025, into a variable rate debt. This swap was accounted for as a fair value hedge. In December 2023, this swap was terminated with a payment received of $6 million on settlement, which had been amortized over the term of the related note.

2 The interest rates of the floating-rate notes are referenced to the daily compounded Canadian overnight repo rate average, plus a margin.

26

HYDRO ONE LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2025 and 2024

(a) Hydro One Inc. long-term debt

As at December 31, 2025, long-term debt of $18,620 million (2024 - $17,070 million) was outstanding, the majority of which was issued under Hydro One Inc.’s MTN Program. In February 2024, Hydro One Inc. filed a short form base shelf prospectus in connection with its MTN Program, which expires in March 2026.

In 2025, Hydro One Inc. issued long-term debt totalling $2,700 million (2024 - $2,750 million) and repaid long-term debt of $1,150 million (2024 - $700 million) under the MTN Program.

(b) Hydro One long-term debt

As at December 31, 2025, long-term debt of $425 million (2024 - $425 million) was outstanding. On August 19, 2024, Hydro One filed a short form base shelf prospectus (Universal Base Shelf Prospectus) with securities regulatory authorities in Canada. The Universal Base Shelf Prospectus allows Hydro One to offer, from time to time in one or more public offerings, debt, equity or other securities, or any combination thereof, during the 25-month period ending in September 2026. As at December 31, 2025, no securities have been issued under the Universal Base Shelf Prospectus. During the years ended December 31, 2025 and 2024, no long-term debt was issued or repaid.

The total long-term debt is presented on the consolidated balance sheets as follows:

As at December 31 (millions of dollars)			2025			2024
Current liabilities:
Long-term debt payable within one year			925			1,150
Long-term liabilities:
Long-term debt			18,092			16,329
Total long-term debt			19,017			17,479

Principal and Interest Payments

As at December 31, 2025, future principal repayments, interest payments, and related weighted-average interest rates were as follows:

			Long-Term Debt Principal Repayments			Interest Payments			Weighted-Average Interest Rate
			(millions of dollars)			(millions of dollars)			(%)
Year 1			925			792			2.8
Year 2			425			775			1.4
Year 3			750			751			4.9
Year 4			1,100			724			3.5
Year 5			800			675			4.8
			4,000			3,717			3.6
Years 6-10			5,760			2,800			4.2
Thereafter			9,285			4,927			4.5
			19,045			11,444			4.2

27

HYDRO ONE LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2025 and 2024

16.    FAIR VALUE OF FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Fair value is considered to be the exchange price in an orderly transaction between market participants to sell an asset or transfer a liability at the measurement date. The fair value definition focuses on an exit price, which is the price that would be received in the sale of an asset or the amount that would be paid to transfer a liability.

Hydro One classifies its fair value measurements based on the following hierarchy, as prescribed by the accounting guidance for fair value, which prioritizes the inputs to valuation techniques used to measure fair value into three levels:

Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities that Hydro One has the ability to access. An active market for the asset or liability is one in which transactions for the asset or liability occur with sufficient frequency and volume to provide ongoing pricing information.

Level 2 inputs are those other than quoted market prices included within Level 1 that are observable, either directly or indirectly, for an asset or liability. Level 2 inputs include, but are not limited to, quoted prices for similar assets or liabilities in an active market, quoted prices for identical or similar assets or liabilities in markets that are not active and inputs other than quoted market prices that are observable for the asset or liability, such as interest-rate curves and yield curves observable at commonly quoted intervals, volatilities, credit risk and default rates. A Level 2 measurement cannot have more than an insignificant portion of the valuation based on unobservable inputs.

Level 3 inputs are any fair value measurements that include unobservable inputs for the asset or liability for more than an insignificant portion of the valuation. A Level 3 measurement may be based primarily on Level 2 inputs.

Non-Derivative Financial Assets and Liabilities

As at December 31, 2025 and 2024, the Company’s carrying amounts of cash and cash equivalents, accounts receivable, due from related parties, short-term notes payable, accounts payable, and due to related parties are representative of fair value due to the short-term nature of these instruments.

Fair Value Measurements of Long-Term Debt

The carrying values and fair values of the Company’s long-term debt as at December 31, 2025 and 2024 are as follows:

			2025			2025			2024			2024
As at December 31 (millions of dollars)			Carrying Value			Fair Value			Carrying Value			Fair Value
Long-term debt, including current portion			19,017			18,721			17,479			17,364

Fair Value Measurements of Derivative Instruments

Fair Value Hedges

As at December 31, 2025 and 2024, Hydro One Inc. had no fair value hedges.

Cash Flow Hedges

As at December 31, 2025 and 2024, Hydro One Inc. had a $425 million, pay-fixed, receive-floating interest-rate swap agreement designated as a cash flow hedge. This cash flow hedge is intended to offset the variability of interest rates between December 21, 2023 and September 21, 2026.

As at December 31, 2025 and 2024, the Company had no derivative instruments classified as undesignated contracts.

Fair Value Hierarchy

The fair value hierarchy of financial assets and liabilities as at December 31, 2025 and 2024 is as follows:

As at December 31, 2025 (millions of dollars)			Carrying Value			Fair  Value			Level 1			Level 2			Level 3
Liabilities:
Long-term debt, including current portion			19,017			18,721			—			18,721			—
Derivative instruments (Note 13)
Cash flow hedges, including current portion			4			4			—			4			—
			19,021			18,725			—			18,725			—

As at December 31, 2024 (millions of dollars)			Carrying Value			Fair  Value			Level 1			Level 2			Level 3
Liabilities:
Long-term debt, including current portion			17,479			17,364			—			17,364			—
Derivative instruments (Notes 13 & 14)
Cash flow hedges, including current portion			7			7			—			7			—
			17,486			17,371			—			17,371			—

28

HYDRO ONE LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2025 and 2024

The fair value of the interest rate swaps designated as cash flow hedges is determined using a discounted cash flow method based on period-end swap yield curves.

The fair value of the long-term debt is based on unadjusted period-end market prices for the same or similar debt of the same remaining maturities.

There were no transfers between any of the fair value levels during the years ended December 31, 2025 or 2024.

Risk Management

Exposure to market risk, credit risk and liquidity risk arises in the normal course of the Company’s business.

Market Risk

Market risk refers primarily to the risk of loss which results from changes in values, foreign exchange rates and interest rates. The Company is exposed to fluctuations in interest rates, as its regulated return on equity is derived using a formulaic approach that takes anticipated interest rates into account. The Company is not currently exposed to material commodity price risk or material foreign exchange risk.

The Company uses a combination of fixed and variable-rate debt to manage the mix of its debt portfolio. The Company also uses derivative financial instruments to manage interest-rate risk. The Company may utilize interest-rate swaps designated as fair value hedges as a means to manage its interest rate exposure to achieve a lower cost of debt. The Company may also utilize interest-rate derivative instruments, such as cash flow hedges, to manage its exposure to short-term interest rates or to lock in interest-rate levels on forecasted financing.

A hypothetical 100 basis point increase in interest rates associated with variable-rate debt would not have resulted in a significant decrease to Hydro One’s net income for the years ended December 31, 2025 and 2024, respectively.

For derivative instruments that are designated and qualify as cash flow hedges, the unrealized gain or loss, after tax, on the derivative instrument is recorded as OCI or OCL and is reclassified to net income or net loss in the same period during which the hedged transaction affects results of operations. The following table shows the amounts recorded in OCI/OCL and reclassified to financing charges for the years ended December 31, 2025 and 2024:

Year ended December 31 (millions of dollars)									2025			2024
Amounts recorded in OCI/OCL
Before tax loss									2			1
After tax loss									1			1
Amounts reclassified to financing charges
Before tax loss (gain)									4			(4)
After tax loss (gain)									3			(3)

This resulted in an AOCL of $3 million related to cash flow hedges as at December 31, 2025 (2024 - $5 million).

The Company estimates that the amount of AOCL, after tax, related to cash flow hedges to be reclassified to results of operations in the next 12 months is approximately $3 million. Actual amounts reclassified to results of operations depend on the interest rate in effect until the derivative contracts mature. For all forecasted transactions, as at December 31, 2025, the maximum term over which the Company is hedging exposures to the variability of cash flows is less than one year.

The Pension Plan manages market risk by diversifying investments in accordance with the Pension Plan’s Statement of Investment Policies and Procedures. Interest rate risk arises from the possibility that changes in interest rates will affect the fair value of the Pension Plan’s financial instruments. In addition, changes in interest rates can also impact discount rates which impact the valuation of the pension and post-retirement and post-employment liabilities. Currency risk is the risk that the value of the Pension Plan’s financial instruments will fluctuate due to changes in foreign currencies relative to the Canadian dollar. Other price risk is the risk that the value of the Pension Plan’s investments in equity securities will fluctuate as a result of changes in market prices, other than those arising from interest risk or currency risk. All three factors may contribute to changes in values of the Pension Plan investments. See Note 18 - Pension and Post-Retirement and Post-Employment Benefits for further details.

Credit Risk

Financial assets create a risk that a counterparty will fail to discharge an obligation, causing a financial loss. As at December 31, 2025 and 2024, there were no significant concentrations of credit risk with respect to any class of financial assets. The Company’s revenue is earned from a broad base of customers. As a result, Hydro One did not earn a material amount of revenue from any single customer. As at December 31, 2025 and 2024, there was no material accounts receivable balance due from any single customer.

As at December 31, 2025, the Company’s allowance for doubtful accounts was $57 million (2024 - $61 million). The allowance for doubtful accounts reflects the Company's CECL for all accounts receivable balances, which are based on historical overdue balances, customer payments and write-offs. As at December 31, 2025, approximately 7% (2024 - 7%) of the Company’s net accounts receivable were outstanding for more than 60 days.

29

HYDRO ONE LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2025 and 2024

Hydro One manages its counterparty credit risk through various techniques including (i) entering into transactions with highly rated counterparties, (ii) limiting total exposure levels with individual counterparties, (iii) entering into master agreements which enable net settlement and the contractual right of offset, and (iv) monitoring the financial condition of counterparties. The Company monitors current credit exposure to counterparties on both an individual and an aggregate basis. The Company’s credit risk for accounts receivable is limited to the carrying amounts on the consolidated balance sheets.

Derivative financial instruments result in exposure to credit risk since there is a risk of counterparty default. The maximum credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts in an asset position at the reporting date. As at December 31, 2025 and 2024, Hydro One’s credit exposure for all derivative instruments and applicable payables was with one financial institution with investment grade credit ratings as counterparty.

The Pension Plan manages its counterparty credit risk with respect to bonds by investing in investment-grade corporate and government bonds and with respect to derivative instruments by transacting only with highly rated financial institutions and by ensuring that exposure is diversified across counterparties.

Liquidity Risk

Liquidity risk refers to the Company’s ability to meet its financial obligations as they come due. Hydro One meets its short-term operating liquidity requirements using cash and cash equivalents on hand, funds from operations, the issuance of commercial paper, and the Operating Credit Facilities. The short-term liquidity under the commercial paper program, the Operating Credit Facilities, and anticipated levels of funds from operations are expected to be sufficient to fund the Company’s operating requirements.

In February 2024, Hydro One Inc. filed a short form base shelf prospectus in connection with its MTN Program, which expires in March 2026. Hydro One’s Universal Base Shelf Prospectus allows it to offer, from time to time in one or more public offerings, debt, equity or other securities, or any combination thereof, during the 25-month period ending on September 19, 2026.

On November 29, 2024, HOHL filed a short form base shelf prospectus (HOHL U.S. Debt Shelf Prospectus) with securities regulatory authorities in Ontario and the U.S., that expires in December 2026. The HOHL U.S. Debt Shelf Prospectus allows HOHL to offer, from time to time in one or more public offerings, debt securities, unconditionally guaranteed by Hydro One. As at December 31, 2025, no securities have been issued under the HOHL U.S. Debt Shelf Prospectus.

On August 18, 2025, Hydro One Inc. 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 Inc. 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 December 31, 2025, no securities have been issued under the HOI U.S. Debt Shelf Prospectus.

The Pension Plan’s short-term liquidity is provided through cash and cash equivalents, contributions, investment income and proceeds from investment transactions. In the event that investments must be sold quickly to meet current obligations, the majority of the Pension Plan’s assets are invested in securities that are traded in an active market and can be readily disposed of as liquidity needs arise.

17.    CAPITAL MANAGEMENT

The Company’s objectives with respect to its capital structure are to maintain effective access to capital on a long-term basis at reasonable rates, and to deliver appropriate financial returns. In order to ensure ongoing access to capital, the Company targets to maintain strong credit quality. As at December 31, 2025 and 2024, the Company’s capital structure was as follows:

As at December 31 (millions of dollars)			2025			2024
Short-term notes payable			100			200
Long-term debt payable within one year			925			1,150
Less: cash and cash equivalents			(549)			(716)
			476			634
Long-term debt			18,092			16,329
Common shares			5,721			5,713
Retained earnings			6,911			6,360
Total capital			31,200			29,036

Hydro One Inc. has customary covenants typically associated with long-term debt. Long-term debt and credit facility covenants limit permissible debt to 75% of its total capitalization, limit the ability to sell assets, and impose a negative pledge provision, subject to customary exceptions. As at December 31, 2025, the Company was in compliance with all financial covenants and limitations associated with the outstanding borrowings and credit facilities.

30

HYDRO ONE LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2025 and 2024

18.    PENSION AND POST-RETIREMENT AND POST-EMPLOYMENT BENEFITS

Hydro One has a Pension Plan, a supplementary pension plan (Supplementary Plan), post-retirement and post-employment benefit plans (Benefit Plans), and a DC Plan.

Pension Plan, Supplementary Plan, and Benefit Plans

The Pension Plan is a defined benefit contributory plan which covers eligible regular employees of Hydro One and its subsidiaries. The Pension Plan provides benefits based on the highest three-year average pensionable earnings up to March 31, 2025. Beginning April 1, 2025, all service for all groups on a go-forward basis will be calculated using the highest five-year average pensionable earnings. For management employees who commenced employment on or after January 1, 2004, and for Society-represented staff hired after November 17, 2005, benefits are based on the highest five-year average pensionable earnings for all their service. After retirement, pensions are indexed to inflation. Membership in the Pension Plan was closed to management employees who were not eligible to join the Pension Plan as of September 30, 2015. These employees are eligible to join the DC Plan.

Company and employee contributions to the 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. Total annual cash Pension Plan employer contributions for 2025 were $68 million (2024 - $75 million). Estimated annual Pension Plan employer contributions for the years 2026, 2027, 2028, 2029, and 2030 are approximately $70 million, $73 million, $77 million, $81 million, and $85 million, respectively.

The Supplementary Plan provides members of the Pension Plan with benefits that would have been earned and payable under the Pension Plan beyond the limitations imposed by the Income Tax Act (Canada). The Supplementary Plan obligation is included with other post-retirement and post-employment benefit obligations on the consolidated balance sheets.

Hydro One recognizes the funded or underfunded status of the Pension Plan and Benefit Plans as an asset or liability on its consolidated balance sheets, with offsetting regulatory assets and regulatory liabilities as appropriate. The funded benefit asset and underfunded benefit obligations for the Pension Plan and Benefit Plans, in the absence of regulatory accounting, would be recognized in AOCI. The impact of changes in assumptions used to measure pension and post-retirement benefit obligations is generally recognized over the expected average remaining service period of the employees and uses the corridor approach for the post-retirement benefit plan. For the post-employment benefit plan, the impact of changes in assumptions are recognized immediately in the net periodic benefit cost. The measurement date for the Plans is December 31.

The following tables provide the components of the funded status of the Company's Pension Plans and Benefit Plans as at December 31, 2025 and 2024:

			Pension Benefits						Post-Retirement and Post-Employment Benefits
Year ended December 31 (millions of dollars)			2025			2024			2025			2024
Change in PBO
PBO, beginning of year			8,686			8,665			1,666			1,603
Current service cost			146			134			61			57
Employee contributions			81			74			—			—
Interest cost			411			401			80			75
Benefits paid			(457)			(427)			(76)			(71)
Net actuarial loss (gain)			40			(161)			19			2
PBO, end of year			8,907			8,686			1,750			1,666

Change in plan assets
Fair value of plan assets, beginning of year			9,333			8,764			—			—
Actual return on plan assets			513			869			—			—
Benefits paid			(457)			(427)			(76)			(71)
Employer contributions			68			75			76			71
Employee contributions			81			74			—			—
Administrative expenses			(21)			(22)			—			—
Fair value of plan assets, end of year			9,517			9,333			—			—
(Funded) unfunded status			(610)			(647)			1,750			1,666

31

HYDRO ONE LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2025 and 2024

Hydro One presents its benefit obligations and plan assets net on its consolidated balance sheets as follows:

			Pension Benefits						Post-Retirement and Post-Employment Benefits
As at December 31 (millions of dollars)			2025			2024			2025			2024
Other assets1			11			12			—			—
Deferred pension assets			610			647			—			—
Accrued liabilities			—			—			78			76
Post-retirement and post-employment benefit liability			—			—			1,672			1,590
Net (funded) unfunded status			(621)			(659)			1,750			1,666

1 Represents the funded status of HOSSM defined benefit pension plan.

The funded or unfunded status of the Pension Plan and Benefit Plans refers to the difference between the fair value of plan assets and the PBO for the Pension Plan and Benefit Plans. The funded/unfunded status changes over time due to several factors, including contribution levels, assumed discount rates and actual returns on plan assets.

The following table provides the PBO, accumulated benefit obligation (ABO) and fair value of plan assets for the Pension Plan:

As at December 31 (millions of dollars)			2025			2024
PBO			8,907			8,686
ABO			8,004			7,848
Fair value of plan assets			9,517			9,333

On an ABO basis, the Pension Plan was funded at 119% as at December 31, 2025 (2024 - 119%). On a PBO basis, the Pension Plan was funded at 107% as at December 31, 2025 (2024 - 107%). The ABO differs from the PBO in that the ABO includes no assumption about future compensation levels.

Components of Net Periodic Benefit Costs

The following table provides the components of the net periodic benefit costs of the Pension Plan for the years ended December 31, 2025 and 2024:

Year ended December 31 (millions of dollars)									2025			2024
Current service cost									146			134
Interest cost									411			401
Expected return on plan assets, net of expenses									(663)			(603)
Amortization of prior service credit									(3)			(3)
Amortization of actuarial (gains) losses									(15)			14
Net periodic benefit credit									(124)			(57)
Charged to results of operations1									21			23

1    The Company accounts for pension costs consistent with their inclusion in OEB-approved rates. During the year ended December 31, 2025, pension costs of $68 million (2024 - $75 million) comprised of $21 million (2024 - $23 million) charged to operations, and $47 million (2024 - $52 million) capitalized as part of the cost of property, plant and equipment and intangible assets.

The following table provides the components of the net periodic benefit costs for the years ended December 31, 2025 and 2024 for the post-retirement and post-employment benefit plans:

Year ended December 31 (millions of dollars)									2025			2024
Current service cost									61			57
Interest cost									80			75
Amortization of prior service cost									10			10
Amortization of actuarial gains									(23)			(29)
Net periodic benefit costs									128			113
Charged to results of operations1									86			74

1    The Company accounts for post-retirement and post-employment costs consistent with their inclusion in OEB-approved rates. During the year ended December 31, 2025, post-retirement and post-employment costs of $128 million (2024 - $113 million) were attributed to labour, of which $86 million (2024 - $74 million) was charged to operations, and $42 million (2024 - $39 million) was capitalized as part of the cost of property, plant and equipment and intangible assets.

Assumptions

The measurement of the obligations of the Pension Plan and Benefit Plans and the costs of providing benefits under the Pension Plan and Benefit Plans involves various factors, including the development of valuation assumptions and accounting policy elections. When developing the required assumptions, the Company considers historical information as well as future expectations. The measurement of benefit obligations and costs is impacted by several assumptions including the discount rate applied to benefit obligations, the long-term expected rate of return on plan assets, Hydro One’s expected level of contributions

32

HYDRO ONE LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2025 and 2024

to the Pension Plan and Benefit Plans, the incidence of mortality, the expected remaining service period of plan participants, the level of compensation and rate of compensation increases, employee age, length of service, and the anticipated rate of increase of health care costs, among other factors. The impact of changes in assumptions used to measure the obligations of the Pension Plan and Benefit Plans is generally recognized over the expected average remaining service period of the plan participants. In selecting the expected rate of return on plan assets, Hydro One considers historical economic indicators that impact asset returns, as well as expectations regarding future long-term capital market performance, weighted by target asset class allocations. In general, equity securities, real estate and private equity investments are forecasted to have higher returns than fixed-income securities.

The following weighted average assumptions were used to determine the benefit obligations as at December 31, 2025 and 2024:

			Pension Benefits						Post-Retirement and Post-Employment Benefits
Year ended December 31			2025			2024			2025			2024
Significant assumptions:
Weighted average discount rate			5.02		%	4.73		%	5.05		%	4.75		%
Rate of compensation scale escalation (long-term)			2.50		%	2.50		%	2.50		%	2.50		%
Rate of cost of living increase			2.00		%	2.00		%	2.00		%	2.00		%
Rate of increase in health care cost trends1			—			—			4.25		%	4.23		%

1 4.79% per annum in 2026, grading down to 4.25% per annum in and after 2032 (2024 - 4.85% per annum in 2025, grading down to 4.23% per annum in and after 2032).

The following weighted average assumptions were used to determine the net periodic benefit costs for the years ended December 31, 2025 and 2024. Assumptions used to determine current year-end benefit obligations are the assumptions used to estimate the subsequent year’s net periodic benefit costs.

Year ended December 31			2025			2024
Pension Benefits:
Weighted average expected rate of return on plan assets			7.20		%	7.00		%
Weighted average discount rate			4.73		%	4.63		%
Rate of compensation scale escalation (long-term)			2.50		%	2.50		%
Rate of cost of living increase			2.00		%	2.00		%
Average remaining service life of employees (years)			15			15
Post-Retirement and Post-Employment Benefits:
Weighted average discount rate			4.75		%	4.63		%
Rate of compensation scale escalation (long-term)			2.50		%	2.50		%
Rate of cost of living increase			2.00		%	2.00		%
Average remaining service life of employees (years)			16.5			16.1
Rate of increase in health care cost trends1			4.23		%	4.23		%

1 4.85% per annum in 2025, grading down to 4.23% per annum in and after 2032 (2024 - 4.92% per annum in 2024, grading down to 4.23% per annum in and after 2032).

The discount rate used to determine the current year pension obligation and the subsequent year’s net periodic benefit costs is based on a yield curve approach. Under the yield curve approach, expected future benefit payments for each plan are discounted by a rate on a third-party bond yield curve corresponding to each duration. The yield curve is based on “AA” long-term corporate bonds. A single discount rate is calculated that would yield the same present value as the sum of the discounted cash flows.

The following approximate life expectancies were used in the mortality assumptions to determine the PBO for the Pension Plan and Benefit Plans as at December 31, 2025 and 2024:

As at December 31			2025			2024
Life expectancy at age 65 for a member currently at:			(years)			(years)
Age 65 - male			24			23
Age 65 - female			27			25
Age 45 - male			26			24
Age 45 - female			28			26

33

HYDRO ONE LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2025 and 2024

Estimated Future Benefit Payments

As at December 31, 2025, estimated future benefit payments to the participants of the Benefit Plans were:

(millions of dollars)			Pension Benefits			Post-Retirement and Post-Employment Benefits
2026			427			78
2027			433			78
2028			439			78
2029			445			79
2030			452			80
2031 through to 2035			2,397			423
Total estimated future benefit payments through to 2035			4,593			816

Components of Regulatory Accounts

A portion of actuarial gains and losses and prior service costs is recorded within regulatory accounts on Hydro One’s consolidated balance sheets to reflect the expected regulatory inclusion of these amounts in future rates, which would otherwise be recorded in OCI. These amounts are reflected in the following table:

Year ended December 31 (millions of dollars)			2025			2024
Pension Benefits:
Net actuarial loss (gain) for the year			210			(405)
Amortization of actuarial gain (loss)			15			(14)
Amortization of prior service credit			3			3
			228			(416)
Post-Retirement and Post-Employment Benefits:
Actuarial loss for the year			28			4
Amortization of actuarial loss			15			18
			43			22

The following table provides the components of regulatory accounts that have not been recognized as components of net periodic benefit costs for the years ended December 31, 2025 and 2024:

Year ended December 31 (millions of dollars)			2025			2024
Pension Benefits:
Actuarial gain			(610)			(647)
Post-Retirement and Post-Employment Benefits:
Actuarial gain			(336)			(376)

34

HYDRO ONE LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2025 and 2024

Pension Plan Assets

Investment Strategy

On a regular basis, Hydro One evaluates its investment strategy to ensure that Pension Plan assets will be sufficient to pay Pension Plan benefits when it comes due. As part of this ongoing evaluation, Hydro One may make changes to its targeted asset allocation and investment strategy. The Pension Plan is managed at a net asset level. The main objective of the Pension Plan is to sustain a certain level of net assets in order to meet the pension obligations of the Company. The Pension Plan fulfils its primary objective by adhering to specific investment policies outlined in its Statement of Investment Policies and Procedures (SIPP), which is reviewed and approved annually by the Human Resource Committee of Hydro One’s Board of Directors. The Company manages net assets by engaging external investment managers who are charged with the fiduciary responsibility of investing existing funds and new funds (current year’s employee and employer contributions) in accordance with the approved SIPP. The performance of the underlying investment managers is monitored through a governance structure. Increases in net assets are a direct result of investment income generated by investments held by the Pension Plan and contributions to the Pension Plan by eligible employees and by the Company. The main use of net assets is for benefit payments to eligible Pension Plan members. 

Pension Plan Asset Mix

As at December 31, 2025, the Pension Plan actual weighted average, target, and range asset allocations were as follows:

			Actual (%)			Target Allocation (%)			Range Allocation (%)
Equity securities			41			40			20 - 55
Debt securities			37			35			30 - 40
Real Estate and Infrastructure			22			25			0 - 35
			100			100

As at December 31, 2025, the Pension Plan held $17 million (2024 - $16 million) Hydro One Inc.’s corporate bonds and $631 million (2024 - $703 million) of debt securities of the Province.

Concentrations of Credit Risk

Hydro One evaluated its Pension Plan’s asset portfolio for the existence of significant concentrations of credit risk as at December 31, 2025 and 2024. Concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, concentrations in a type of industry, and concentrations in individual funds. As at December 31, 2025 and 2024, there were no significant concentrations (defined as greater than 10% of plan assets) of risk in the Pension Plan’s assets.

The Pension Plan's Statement of Investment Beliefs and Guidelines provides guidelines and restrictions for eligible investments taking into account credit ratings, maximum investment exposure and other controls in order to limit the impact of this risk. The Pension Plan manages its counterparty credit risk with respect to bonds by investing in investment-grade and government bonds and with respect to derivative instruments by transacting only with highly rated financial institutions, and also by ensuring that exposure is diversified across counterparties. The risk of default on transactions in listed securities is considered minimal, as the trade will fail if either party to the transaction does not meet its obligation.

Fair Value Measurements

The following tables present the Pension Plan assets and liabilities measured and recorded at fair value on a recurring basis and their level within the fair value hierarchy as at December 31, 2025 and 2024:

As at December 31, 2025 (millions of dollars)			Level 1			Level 2			Level 3			Total
Pooled funds			—			—			3,277			3,277
Cash and cash equivalents			124			—			—			124
Short-term securities			—			182			—			182
Derivative instruments			—			2			—			2
Corporate shares - Canadian			102			—			—			102
Corporate shares - Foreign			2,736			255			—			2,991
Bonds and debentures - Canadian			—			2,677			—			2,677
Bonds and debentures - Foreign			—			106			—			106
Total fair value of plan assets1			2,962			3,222			3,277			9,461
Derivative instruments			—			1			—			1
Total fair value of plan liabilities1			—			1			—			1

1 As at December 31, 2025, the total fair value of Pension Plan assets and liabilities excludes $62 million of interest and dividends receivable, $4 million of sold investments receivable, $5 million of pension administration expenses payable, $2 million of taxes payable, $nil payable to participants, and $2 million of purchased investments payable.

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HYDRO ONE LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2025 and 2024

As at December 31, 2024 (millions of dollars)			Level 1			Level 2			Level 3			Total
Pooled funds			—			—			3,142			3,142
Cash and cash equivalents			106			—			—			106
Short-term securities			—			171			—			171
Derivative instruments			—			1			—			1
Corporate shares - Canadian			116			—			—			116
Corporate shares - Foreign			2,695			247			—			2,942
Bonds and debentures - Canadian			—			2,717			—			2,717
Bonds and debentures - Foreign			—			95			—			95
Total fair value of plan assets1			2,917			3,231			3,142			9,290
Derivative instruments			—			3			—			3
Total fair value of plan liabilities1			—			3			—			3

1 As at December 31, 2024, the total fair value of Pension Plan assets and liabilities excludes $57 million of interest and dividends receivable, $1 million of sold investments receivable, $6 million of pension administration expenses payable, $2 million of taxes payable, $3 million payable to participants, and $1 million of purchased investments payable.

See Note 16 - Fair Value of Financial Instruments and Risk Management for a description of levels within the fair value hierarchy.

Changes in the Fair Value of Financial Instruments Classified in Level 3

The following table summarizes the changes in fair value of financial instruments classified in Level 3 for the years ended December 31, 2025 and 2024. The Pension Plan classifies financial instruments as Level 3 when the fair value is measured based on at least one significant input that is not observable in the markets or due to lack of liquidity in certain markets. The gains and losses presented in the table below could, therefore, include changes in fair value based on both observable and unobservable inputs. The Level 3 financial instruments are comprised of pooled funds whose valuations are provided by the investment managers. Sensitivity analysis is not provided as the underlying assumptions used by the investment managers are not available.

Year ended December 31 (millions of dollars)			2025			2024
Fair value, beginning of year			3,142			2,769
Realized and unrealized gains			136			262
Purchases			138			203
Sales and disbursements			(139)			(92)
Fair value, end of year			3,277			3,142

There were no transfers between any of the fair value levels during the years ended December 31, 2025 and 2024.

Valuation Techniques Used to Determine Fair Value

Pooled funds mainly consist of private equity, real estate infrastructure and private debt investments. Private equity investments represent private equity funds that invest in operating companies that are not publicly traded on a stock exchange. Investment strategies in private equity include limited partnerships in businesses that are characterized by high internal growth and operational efficiencies, venture capital, leveraged buyouts and special situations such as distressed investments. Real estate and infrastructure investments represent funds that invest in real assets which are not publicly traded on a stock exchange. Investment strategies in real estate include limited partnerships that seek to generate a total return through income and capital growth by investing primarily in global and Canadian limited partnerships. Investment strategies in infrastructure include limited partnerships in core infrastructure assets focusing on assets that are expected to generate stable, long-term cash flows and deliver incremental returns relative to conventional fixed-income investments. Private equity, real estate and infrastructure valuations are reported by the fund manager and are based on the valuation of the underlying investments which includes inputs such as cost, operating results, discounted future cash flows and market-based comparable data. Private debt valuations are reported by the fund manager. Private debt is credit that is extended to companies on a bilaterally negotiated basis. It is not readily marketable and takes a wide range of forms, such as senior secured and unsecured loans, infrastructure project financing, investments secured by real estate assets, and securitized lease/loan obligations supported by a pool of assets. Since these valuation inputs are not highly observable, private equity, real estate infrastructure and private debt investments have been categorized as Level 3 within pooled funds.

Cash equivalents consist of demand cash deposits held with banks and cash held by the investment managers. Cash equivalents are categorized as Level 1.

Short-term securities are valued at cost plus accrued interest, which approximates fair value due to their short-term nature. Short-term securities are categorized as Level 2.

Derivative instruments are used to hedge the Pension Plan’s foreign currency exposure back to Canadian dollars. The notional principal amount of contracts outstanding as at December 31, 2025 was $405 million (2024 - $391 million). The most significant currencies being hedged against the Canadian dollar are the United States dollar, euro, and British pound sterling. The net

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HYDRO ONE LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2025 and 2024

realized loss on contracts for the year ended December 31, 2025 was $4 million (2024 - $3 million net realized loss). The terms to maturity of the forward exchange contracts as at December 31, 2025 are within three months. The fair value is determined using standard interpolation methodology primarily based on the World Markets exchange rates. Derivative instruments are categorized as Level 2.

Corporate shares are valued based on quoted prices in active markets and are categorized as Level 1. Corporate shares which are valued based on quoted prices in active markets, but held within a pension investment holding company, are categorized as Level 2. Investments denominated in foreign currencies are translated into Canadian currency at year-end rates of exchange.

Bonds and debentures are presented at published closing trade quotations and are categorized as Level 2.

DC Plan

Hydro One established a DC Plan effective January 1, 2016. The DC Plan covers eligible management employees hired on or after January 1, 2016, as well as management employees hired before January 1, 2016 who were not eligible to join the Pension Plan as of September 30, 2015. Members of the DC Plan have an option to contribute 4%, 5% or 6% of their pensionable earnings, with matching contributions by Hydro One up to an annual contribution limit. There is also a Supplementary Notional Plan that provides members of the DC Plan with employer contributions beyond the limitations imposed by the Income Tax Act (Canada) in the form of credits to a notional account. Hydro One contributions to the DC Plan for the year ended December 31, 2025 were $5 million (2024 - $5 million).

19.    ENVIRONMENTAL LIABILITIES

The following tables show the movements in environmental liabilities for the years ended December 31, 2025 and 2024:

Year ended December 31, 2025 (millions of dollars)			PCB			LAR			Total
Environmental liabilities - beginning			6			41			47
Expenditures			(4)			(1)			(5)
Revaluation adjustment			(1)			3			2
Environmental liabilities - ending			1			43			44
Less: current portion			(1)			(6)			(7)
			—			37			37

Year ended December 31, 2024 (millions of dollars)			PCB			LAR			Total
Environmental liabilities - beginning			39			40			79
Expenditures			(34)			(3)			(37)
Revaluation adjustment			1			4			5
Environmental liabilities - ending			6			41			47
Less: current portion			(6)			(5)			(11)
			—			36			36

As at December 31, 2025, the estimated future environmental expenditures were as follows:

(millions of dollars)
2026			7
2027			6
2028			2
2029			1
2030			2
Thereafter			26
			44

There are uncertainties in estimating future environmental costs due to potential external events such as changes in legislation or regulations, and advances in remediation technologies. In determining the amounts to be recorded as environmental liabilities, the Company estimates the current cost of completing required work and makes assumptions as to when the future expenditures will actually be incurred in order to generate future cash flow information. All factors used in estimating the Company’s environmental liabilities represent management’s best estimates of the present value of costs required to meet existing legislation or regulations. However, it is reasonably possible that numbers or volumes of contaminated assets, cost estimates to perform work, inflation assumptions and the assumed pattern of annual cash flows may differ significantly from the Company’s current assumptions. In addition, with respect to the PCB environmental liability, the availability of critical resources such as skilled labour and replacement assets and the ability to take maintenance outages in critical facilities may influence the timing of expenditures.

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HYDRO ONE LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2025 and 2024

PCBs

Environment and Climate Change Canada regulations, enacted under the Canadian Environmental Protection Act, 1999, govern the management, storage and disposal of PCBs based on certain criteria, including type of equipment, in-use status, and PCB-contamination thresholds. Under previous regulations, Hydro One’s PCBs were to be disposed of by the end of 2025, with the exception of specifically exempted equipment. On December 31st, 2025, regulations amending the Canadian Environmental Protection Act, 1999 were published in the Canada Gazette, Part II. The amendments include deferring the end-of-use deadline for certain PCB-containing electrical equipment from December 31, 2025 to December 31, 2026. Contaminated equipment will generally be replaced, or will be decontaminated by removing PCB-contaminated insulating oil and retro filling with replacement oil that contains PCBs in concentrations of less than 2 ppm.

As at December 31, 2025, the Company’s best estimate of the total future expenditures to comply with current PCB regulations was $1 million (2024 - $6 million). These expenditures are expected to be incurred in 2026. As a result of its annual review of environmental liabilities, the Company recorded a revaluation adjustment in 2025 to decrease the PCB environmental liability by $1 million (2024 - increase of $1 million).

LAR

As at December 31, 2025, the Company’s best estimate of the total estimated future expenditures to complete its LAR program was $43 million (2024 - $41 million). These expenditures are expected to be incurred over the period from 2026 to 2051. As a result of its annual review of environmental liabilities, the Company recorded a revaluation adjustment in 2025 to increase the LAR environmental liability by $3 million (2024 - $4 million).

20.    ASSET RETIREMENT OBLIGATIONS

Hydro One records a liability for the estimated future expenditures for the removal and disposal of asbestos-containing materials installed in some of its facilities, as well as for the estimated expenditure for the future decommissioning and removal of some diesel generating stations and related assets operated by its subsidiary, Hydro One Remotes.

Asset retirement obligations, which represent legal obligations associated with the retirement of certain tangible long-lived assets, are computed as the present value of the projected expenditures for the future retirement of specific assets and are recognized in the period in which the liability is incurred, if a reasonable estimate can be made. If the asset remains in service at the recognition date, the present value of the liability is added to the carrying amount of the associated asset in the period the liability is incurred and this additional carrying amount is depreciated over the remaining life of the asset. If an asset retirement obligation is recorded in respect of an out-of-service asset, the asset retirement cost is charged to results of operations. Subsequent to the initial recognition, the liability is adjusted for any revisions to the estimated future cash flows associated with the asset retirement obligation, which can occur due to a number of factors including, but not limited to, cost escalation, changes in technology applicable to the assets to be retired, changes in legislation or regulations, as well as for accretion of the liability due to the passage of time until the obligation is settled. Depreciation expense is adjusted prospectively for any increases or decreases to the carrying amount of the associated asset.

Some of the Company’s transmission and distribution assets, particularly those located on unowned easements and rights-of-way, may have asset retirement obligations, conditional or otherwise. The majority of the Company’s easements and rights-of-way are either of perpetual duration or are automatically renewed annually. Land rights with finite terms are generally subject to extension or renewal. As the Company expects to use the majority of its facilities in perpetuity, no asset retirement obligations have been recorded for these assets. If, at some future date, a particular facility is shown not to meet the perpetuity assumption, it will be reviewed to determine whether an estimable asset retirement obligation exists. In such a case, an asset retirement obligation would be recorded at that time.

In determining the amounts to be recorded as asset retirement obligations, the Company estimates the current fair value for completing required work and makes assumptions as to when the future expenditures will actually be incurred, in order to generate future cash flow information. A long-term inflation assumption of approximately 2% has been used to express these current cost estimates as estimated future expenditures. Future expenditures have been discounted using factors ranging from approximately 1.0% to 3.0% (2024 - 1.0% to 3.0%) depending on the appropriate rate for the period when expenditures are expected to be incurred. All factors used in estimating the Company’s asset retirement obligations represent management’s best estimates of the cost required to meet existing legislation or regulations. However, it is reasonably possible that numbers or volumes of contaminated assets, cost estimates to perform work, inflation assumptions and the assumed pattern of annual cash flows may differ significantly from the Company’s current assumptions. Asset retirement obligations are reviewed annually or more frequently if significant changes in regulations or other relevant factors occur. Estimate changes are accounted for prospectively. As a result of its annual review of asset retirement obligations, the Company recorded a revaluation adjustment in 2025 to increase the asset retirement obligations related to the removal and disposal of asbestos-containing materials installed in some of its facilities by $3 million (2024 - $nil) and the asset retirement obligations related to decommissioning and removal of diesel generating station within the Hydro One Remotes operating territory by $1 million (2024 - $2 million).

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HYDRO ONE LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2025 and 2024

As at December 31, 2025, Hydro One had recorded total asset retirement obligations of $43 million (2024 - $38 million), primarily consisting of the estimated future expenditures associated with the removal and disposal of asbestos-containing materials installed in some of its facilities of $22 million (2024 - $18 million), and the decommissioning and removal of diesel generating stations of $20 million (2024 - $19 million).

21.    LEASES

Hydro One has operating lease contracts for buildings used in administrative and service-related functions and storing telecommunications equipment. These leases have terms between three and five years with renewal options of additional three- to five-year terms at prevailing market rates at the time of extension. All leases include a clause to enable upward revision of the rental charge on an annual basis or on renewal according to prevailing market conditions or pre-established rents. There are no restrictions placed upon Hydro One by entering into these leases. Renewal options are included in the lease term when their exercise is reasonably certain. The Company also has a few finance lease arrangements, all of which were fully prepaid at commencement and are immaterial to the consolidated financial statements. Other information related to the Company's operating leases was as follows:

Year ended December 31 (millions of dollars)									2025			2024
Lease expense									17			17
Lease payments made									17			16
As at December 31									2025			2024
Weighted-average remaining lease term1 (years)									3			4
Weighted-average discount rate									2.8		%	2.9		%

1 Includes renewal options that are reasonably certain to be exercised.

As at December 31, 2025, future minimum operating lease payments were as follows:

(millions of dollars)
2026						16
2027						14
2028						10
2029						3
2030						1
Thereafter						1
Total undiscounted minimum lease payments						45
Less: discounting minimum lease payments to present value						(2)
Total discounted minimum lease payments						43

As at December 31, 2024, future minimum operating lease payments were as follows:

(millions of dollars)
2025						17
2026						15
2027						13
2028						10
2029						2
Thereafter						2
Total undiscounted minimum lease payments						59
Less: discounting minimum lease payments to present value						(4)
Total discounted minimum lease payments						55

Hydro One presents its ROU assets and lease obligations on the consolidated balance sheets as follows:

As at December 31 (millions of dollars)			2025			2024
Other long-term assets (Note 12)			47			55
Accounts payable and other current liabilities (Note 13)			14			14
Other long-term liabilities (Note 14)			29			41

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HYDRO ONE LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2025 and 2024

22.    SHARE CAPITAL

Common Shares

The Company is authorized to issue an unlimited number of common shares. As at December 31, 2025, the Company had 599,781,811 (2024 - 599,435,650) common shares issued and outstanding.

The amount and timing of any dividends payable by Hydro One is at the discretion of the Hydro One Board of Directors and is established on the basis of Hydro One’s results of operations, maintenance of its deemed regulatory capital structure, financial condition, cash requirements, the satisfaction of solvency tests imposed by corporate laws for the declaration and payment of dividends and other factors that the Board of Directors may consider relevant.

The following tables presents the changes to common shares during the years ended December 31, 2025 and 2024:

			Ownership by
Year ended December 31, 2025 (number of shares)			Public			Province			Total
Common shares - beginning			317,023,002			282,412,648			599,435,650
Common shares issued - LTIP1			10,492			—			10,492
Common shares issued - share grants2			335,669			—			335,669
Common shares - ending			317,369,163			282,412,648			599,781,811
			52.9		%	47.1		%	100		%

1 In 2025, Hydro One issued 10,492 common shares from treasury in accordance with provisions of the LTIP.

2 In 2025, Hydro One issued 335,669 common shares from treasury in accordance with provisions of the Power Workers’ Union (PWU) and the Society Share Grant Plans.

			Ownership by
Year ended December 31, 2024 (number of shares)			Public			Province			Total
Common shares - beginning			316,664,419			282,412,648			599,077,067
Common shares issued - LTIP1			9,905			—			9,905
Common shares issued - share grants2			348,678			—			348,678
Common shares - ending			317,023,002			282,412,648			599,435,650
			52.9		%	47.1		%	100		%

1 In 2024, Hydro One issued 9,905 common shares from treasury in accordance with provisions of the LTIP.

2 In 2024, Hydro One issued 348,678 common shares from treasury in accordance with provisions of the PWU and the Society Share Grant Plans.

Preferred Shares

The Company is authorized to issue an unlimited number of preferred shares, issuable in series. As at December 31, 2025 and 2024, two series of preferred shares were authorized for issuance: the Series 1 preferred shares and the Series 2 preferred shares. As at December 31, 2025, and 2024, the Company had no Series 1 preferred shares and no Series 2 preferred shares issued and outstanding.

Hydro One may from time to time issue preferred shares in one or more series. Prior to issuing shares in a series, the Hydro One Board of Directors is required to fix the number of shares in the series and determine the designation, rights, privileges, restrictions and conditions attaching to that series of preferred shares. Holders of Hydro One’s preferred shares are not entitled to receive notice of, to attend or to vote at any meeting of the shareholders of Hydro One except that votes may be granted to a series of preferred shares when dividends have not been paid on any one or more series as determined by the applicable series provisions. Each series of preferred shares ranks on parity with every other series of preferred shares, and are entitled to a preference over the common shares and any other shares ranking junior to the preferred shares, with respect to dividends and the distribution of assets and return of capital in the event of the liquidation, dissolution or winding up of Hydro One.

Share Ownership Restrictions

The Electricity Act imposes share ownership restrictions on securities of Hydro One carrying a voting right (Voting Securities). These restrictions provide that no person or company (or combination of persons or companies acting jointly or in concert) may beneficially own or exercise control or direction over more than 10% of any class or series of Voting Securities, including common shares of the Company (Share Ownership Restrictions). The Share Ownership Restrictions do not apply to Voting Securities held by the Province, nor to an underwriter who holds Voting Securities solely for the purpose of distributing those securities to purchasers who comply with the Share Ownership Restrictions.

23.    DIVIDENDS

In 2025, common share dividends in the amount of $788 million (2024 - $743 million) were declared and paid.

See Note 32 - Subsequent Events for dividends declared subsequent to December 31, 2025.

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HYDRO ONE LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2025 and 2024

24.    EARNINGS PER COMMON SHARE

Basic earnings per common share (EPS) is calculated by dividing net income attributable to common shareholders of Hydro One by the weighted-average number of common shares outstanding.

Diluted EPS is calculated by dividing net income attributable to common shareholders of Hydro One by the weighted-average number of common shares outstanding adjusted for the effects of potentially dilutive stock-based compensation plans, including the share grant plans and LTIP, which are calculated using the treasury stock method.

									2025			2024
Net income attributable to common shareholders (millions of dollars)									1,339			1,156
Weighted-average number of shares
Basic									599,692,817			599,342,299
Effect of dilutive stock-based compensation plans									1,020,183			1,318,179
Diluted									600,713,000			600,660,478
EPS
Basic									$2.23			$1.93
Diluted									$2.23			$1.92

25.    STOCK-BASED COMPENSATION

Share Grant Plans

Hydro One has two share grant plans (Share Grant Plans), one for the benefit of certain members of the PWU (PWU Share Grant Plan) and one for the benefit of certain members of the Society (Society Share Grant Plan).

The PWU Share Grant Plan provides for the issuance of common shares of Hydro One from treasury to certain eligible members of the PWU annually, commencing on April 1, 2017 and continuing until the earlier of April 1, 2028 or the date an eligible employee no longer meets the eligibility criteria of the PWU Share Grant Plan. To be eligible, an employee must be a member of the Pension Plan on April 1, 2015, be employed on the date that the annual share issuance occurs and continue to have under 35 years of service. The requisite service period for the PWU Share Grant Plan began on July 3, 2015, which is the date that the share grant plan was ratified by the PWU. The number of common shares issued annually to each eligible employee will be equal to 2.7% of such eligible employee’s salary as of April 1, 2015, divided by $20.50, being the price of the common shares of Hydro One in its Initial Public Offering (IPO). The aggregate number of common shares issuable under the PWU Share Grant Plan shall not exceed 3,981,763 common shares. In 2015, 3,979,062 common shares were granted under the PWU Share Grant Plan.

The Society Share Grant Plan provides for the issuance of common shares of Hydro One from treasury to certain eligible members of the Society annually, commencing on April 1, 2018 and continuing until the earlier of April 1, 2029 or the date an eligible employee no longer meets the eligibility criteria of the Society Share Grant Plan. To be eligible, an employee must be a member of the Pension Plan on September 1, 2015, be employed on the date that the annual share issuance occurs and continue to have under 35 years of service. Therefore, the requisite service period for the Society Share Grant Plan began on September 1, 2015. The number of common shares issued annually to each eligible employee will be equal to 2.0% of such eligible employee’s salary as of September 1, 2015, divided by $20.50, being the price of the common shares of Hydro One in its IPO. The aggregate number of common shares issuable under the Society Share Grant Plan shall not exceed 1,434,686 common shares. In 2015, 1,433,292 common shares were granted under the Society Share Grant Plan.

The fair value of the Hydro One 2015 share grants of $111 million was estimated based on the grant date share price of $20.50 and is recognized using the graded-vesting attribution method as the share grant plans have both a performance condition and a service condition. In 2025, 335,669 common shares (2024 - 348,678) were issued under the Share Grant Plans. Total share-based compensation recognized during 2025 was $1 million (2024 - $2 million) and was recorded as a regulatory asset.

A summary of share grant activity under the Share Grant Plans during the years ended December 31, 2025 and 2024 is presented below:

Year ended December 31, 2025			Share Grants (number of common shares)						Weighted-Average Price
Share grants outstanding - beginning						1,407,294			$20.50
Vested and issued1						(335,669)			—
Forfeited						(46,481)			$20.50
Share grants outstanding - ending						1,025,144			$20.50

1 In 2025, Hydro One issued 335,669 common shares from treasury to eligible employees in accordance with provisions of the Share Grant Plans.

41

HYDRO ONE LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2025 and 2024

Year ended December 31, 2024			Share Grants (number of common shares)						Weighted-Average Price
Share grants outstanding - beginning						1,782,376			$20.50
Vested and issued1						(348,678)			—
Granted						1,092			—
Forfeited						(27,496)			$20.50
Share grants outstanding - ending						1,407,294			$20.50

1    In 2024, Hydro One issued 348,678 common shares from treasury to eligible employees in accordance with provisions of the Share Grant Plans.

Directors' DSU Plan

Under the Directors’ DSU Plan, directors can elect to receive credit for their annual cash retainer in a notional account of DSUs in lieu of cash. Hydro One’s Board of Directors may also determine from time to time that special circumstances exist that would reasonably justify the grant of DSUs to a director as compensation in addition to any regular retainer or fee to which the director is entitled. Each DSU represents a unit with an underlying value equivalent to the value of one common share of the Company and is entitled to accrue common share dividend equivalents in the form of additional DSUs at the time dividends are paid, subsequent to declaration by Hydro One’s Board of Directors.

A summary of DSU awards activity under the Directors' DSU Plan during the years ended December 31, 2025 and 2024 is presented below:

Year ended December 31 (number of DSUs)									2025			2024
DSUs outstanding - beginning									107,296			94,624
Granted									21,033			22,293
Settled									(26,073)			(9,621)
DSUs outstanding - ending									102,256			107,296

For the year ended December 31, 2025, an expense of $2 million (2024 - $1 million) was recognized in earnings with respect to the Directors' DSU Plan. As at December 31, 2025, a liability of $6 million (2024 - $5 million) related to Directors' DSUs has been recorded at the closing price of the Company's common shares of $54.64. This liability is included in other long-term liabilities on the consolidated balance sheets.

Management DSU Plan

Under the Management DSU Plan, eligible executive employees can elect to receive a specified proportion of their annual short-term incentive in a notional account of DSUs in lieu of cash. Each DSU represents a unit with an underlying value equivalent to the value of one common share of the Company and is entitled to accrue common share dividend equivalents in the form of additional DSUs at the time dividends are paid, subsequent to declaration by Hydro One’s Board of Directors.

A summary of DSU awards activity under the Management DSU Plan during the years ended December 31, 2025 and 2024 is presented below:

Year ended December 31 (number of DSUs)									2025			2024
DSUs outstanding - beginning									85,690			134,370
Granted									14,219			16,600
Settled									(19,505)			(65,280)
DSUs outstanding - ending									80,404			85,690

For the year ended December 31, 2025, an expense of $2 million (2024 - $1 million) was recognized in earnings with respect to the Management DSU Plan. As at December 31, 2025, a liability of $4 million (2024 - $4 million) related to Management DSUs has been recorded at the closing price of the Company's common shares of $54.64. This liability is included in other long-term liabilities on the consolidated balance sheets.

42

HYDRO ONE LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2025 and 2024

Employee Share Ownership Plan

In 2015, Hydro One established Employee Share Ownership Plans (ESOP) for certain eligible management and non-represented employees (Management ESOP) and for certain eligible Society-represented staff (Society ESOP). Under the Management ESOP, the eligible management and non-represented employees may contribute between 1% and 6% of their base salary towards purchasing common shares of Hydro One. The Company matches 50% of their contributions, up to a maximum Company contribution of $25,000 per calendar year. Under the Society ESOP, the eligible Society-represented staff may contribute between 1% and 4% of their base salary towards purchasing common shares of Hydro One. The Company matches 25% of their contributions, with no maximum Company contribution per calendar year.

In 2024, Hydro One established ESOP for certain eligible PWU represented staff (PWU ESOP). Under the PWU ESOP, the eligible PWU-represented staff may contribute between 1% and 4% of their base salary towards purchasing common shares of Hydro One. The Company matches 33% of their contribution, with no maximum Company contribution per calendar year. In 2025, Company contributions made under the ESOP were $9 million (2024 - $5 million).

LTIP

Effective August 31, 2015, the Board of Directors of Hydro One adopted an LTIP. Under the LTIP, long-term incentives were granted to certain executive and management employees of Hydro One and its subsidiaries, and all equity-based awards would either be settled in newly issued shares of Hydro One from treasury or cash, subject to Hydro One’s discretion, consistent with the provisions of the plan which also permit the participants to surrender a portion of their awards to satisfy related withholding taxes requirements. The aggregate number of shares issuable under the LTIP shall not exceed 11,900,000 shares of Hydro One.

The LTIP provides flexibility to award a range of vehicles, including Performance Share Units (PSUs), Restricted Share Units (RSUs), stock options, share appreciation rights, restricted shares, DSUs, and other share-based awards. The mix of vehicles is intended to vary by role to recognize the level of executive accountability for overall business performance.

PSUs and RSUs

A summary of PSU and RSU awards activity under the LTIP during the years ended December 31, 2025 and 2024 is presented below:

			PSUs						RSUs
Year ended December 31 (number of units)			2025			2024			2025			2024
Units outstanding - beginning			286,554			142,925			322,925			186,971
Granted			179,731			189,104			154,754			158,757
Forfeited			(45,655)			(24,918)			(60,660)			(20,377)
Vested and issued			(21,449)			(20,557)			(25,396)			(2,426)
Units outstanding - ending			399,181			286,554			391,623			322,925

The grant date total fair value of the awards granted during the year ended December 31, 2025 was $16 million (2024 - $14 million). The compensation expense related to the PSU and RSU awards recognized by the Company during the year ended December 31, 2025 was $11 million (2024 - $10 million).

26.    NONCONTROLLING INTEREST

Total noncontrolling interest consists of noncontrolling interests attributable to B2M LP, NRLP and CLLP. The following tables show the movements in total noncontrolling interest during the years ended December 31, 2025 and 2024:

Year ended December 31, 2025 (millions of dollars)			Temporary Equity						Equity			Total
Noncontrolling interest - beginning						19			65			84
Contributions from sale of noncontrolling interest						—			16			16
Net income attributable to noncontrolling interest						2			8			10
Distributions to noncontrolling interest						(2)			(10)			(12)
Noncontrolling interest - ending						19			79			98

Year ended December 31, 2024 (millions of dollars)			Temporary Equity						Equity			Total
Noncontrolling interest - beginning						20			65			85
Net income attributable to noncontrolling interest						2			7			9
Distributions to noncontrolling interest						(3)			(7)			(10)
Noncontrolling interest - ending						19			65			84

43

HYDRO ONE LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2025 and 2024

B2M LP

On December 17, 2014, the Saugeen Ojibway Nation (SON) acquired a 34.2% equity interest in B2M LP for consideration of $72 million, representing the fair value of the equity interest acquired. The SON’s investment in B2M LP consists of $50 million of Class A units and $22 million of Class B units.

The Class B units have a mandatory put option which requires that upon the occurrence of an enforcement event (i.e., an event of default such as a debt default by the SON or insolvency event), Hydro One purchases the Class B units of B2M LP for net book value on the redemption date. The noncontrolling interest relating to the Class B units is classified on the consolidated balance sheet as temporary equity because the redemption feature is outside the control of the Company. The balance of the noncontrolling interest is classified within equity.

The following tables show the movements in B2M LP noncontrolling interest during the years ended December 31, 2025 and 2024:

Year ended December 31, 2025 (millions of dollars)			Temporary Equity						Equity			Total
Noncontrolling interest - beginning						19			44			63
Net income attributable to noncontrolling interest						2			5			7
Distributions to noncontrolling interest						(2)			(7)			(9)
Noncontrolling interest - ending						19			42			61

Year ended December 31, 2024 (millions of dollars)			Temporary Equity						Equity			Total
Noncontrolling interest - beginning						20			44			64
Net income attributable to noncontrolling interest						2			5			7
Distributions to noncontrolling interest						(3)			(5)			(8)
Noncontrolling interest - ending						19			44			63

NRLP

On September 18, 2019, Hydro One Networks sold to the Six Nations of the Grand River Development Corporation and, through a trust, to the Mississaugas of the Credit First Nation a 25.0% and 0.1% equity interest in NRLP partnership units, respectively, for total consideration of $12 million, representing the fair value of the equity interest acquired. On January 31, 2020, the Mississaugas of the Credit First Nation purchased an additional 19.9% equity interest in NRLP partnership units from Hydro One Networks for total cash consideration of $9 million. Following this transaction, Hydro One’s interest in the equity portion of NRLP partnership units was reduced to 55%, with the Six Nations of the Grand River Development Corporation and the Mississaugas of the Credit First Nation owning 25% and 20%, respectively, of the equity interest in NRLP partnership units. The First Nations Partners' noncontrolling interest in NRLP is classified within equity.

The following table shows the movements in NRLP noncontrolling interest during the years ended December 31, 2025 and 2024:

Year ended December 31 (millions of dollars)									2025			2024
Noncontrolling interest - beginning									21			21
Net income attributable to noncontrolling interest									2			2
Distributions to noncontrolling interest									(3)			(2)
Noncontrolling interest - ending									20			21

CLLP

On December 17, 2024, transmission assets totalling $203 million were transferred from Hydro One Networks to CLLP. Effective June 1, 2025, Hydro One Networks sold 10% equity interest to Deshkan Ziibiing Chippewas of the Thames First Nation for cash consideration of $8 million. Effective July 1, 2025, Hydro One Networks sold an additional 10% equity interest to Southwest Indigenous Transmission Limited Partnership, owned by the Caldwell First Nation, for cash consideration of $8 million. The total consideration of $16 million represents the fair value of the equity interest acquired. Following these transactions, Hydro One’s interest in the equity portion of CLLP partnership units was reduced to 80%. The First Nations Partners' noncontrolling interest in CLLP is classified within equity.

The following table shows the movements in CLLP noncontrolling interest during the years ended December 31, 2025 and 2024:

Year ended December 31 (millions of dollars)									2025			2024
Noncontrolling interest - beginning									—			—
Contributions from sale of noncontrolling interest									16			—
Net income attributable to noncontrolling interest									1			—
Noncontrolling interest - ending									17			—

44

HYDRO ONE LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2025 and 2024

27.    RELATED PARTY TRANSACTIONS

The Province is a shareholder of Hydro One with approximately 47.1% (2024 - 47.1%) ownership as at December 31, 2025. The Ministry of Energy and Mines (Ministry) and the Ministry of Infrastructure (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), and the OEB are related parties to Hydro One because they are controlled or significantly influenced by the Ministry. 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 years ended December 31, 2025 and 2024:

Year ended December 31 (millions of dollars)
Related Party			Transaction									2025			2024
Province			Dividends paid									370			350
Ministry			Broadband subsidy1									27			—
MOI			Broadband subsidy1									19			43
IESO			Power purchased									3,011			2,686
			Revenues for transmission services									2,388			2,252
			Amounts related to electricity rebates									1,110			1,170
			Distribution revenues related to rural rate protection									256			255
			Distribution revenues related to Wataynikaneyap Power LP									133			119
			Distribution revenues related to supply of electricity to remote northern communities									50			48
			Funding received related to Conservation and Demand Management programs									—			1
OPG			Power purchased									23			18
			Transmission revenues related to provision of services and supply of electricity									2			2
			Distribution revenues related to provision of services and supply of electricity									8			5
			Other revenues related to provision of services and supply of electricity									2			1
			Capital contribution received from OPG									20			3
			Costs related to the purchase of services									2			1
OEFC			Power purchased from power contracts administered by the OEFC									2			1
OEB			OEB fees									14			12

1 On October 31, 2024, the 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 as defined under Building Broadband Faster Act (Ontario). A portion of these subsidies is used to reimburse Hydro One Networks on behalf of ISPs for their share of enablement costs incurred to facilitate the program to date. During 2025, Ministry replaced MOI in making broadband subsidy payments to Hydro One.

Sales to and purchases from related parties are based on the requirements of the OEB’s Affiliate Relationships Code. Outstanding balances as at period end are interest-free and settled in cash. Invoices are issued monthly, and amounts are due and paid on a monthly basis.

28.    CONSOLIDATED STATEMENTS OF CASH FLOWS

The changes in non-cash balances related to operations consist of the following:

Year ended December 31 (millions of dollars)									2025			2024
Accounts receivable									(169)			(81)
Due from related parties									(84)			(12)
Materials and supplies									(1)			6
Prepaid expenses and other assets (Note 8)									2			(26)
Other long-term assets									(5)			(34)
Accounts payable (Note 13)									23			7
Accrued liabilities									95			136
Unearned revenue (Note 13)									(23)			125
Due to related parties									137			40
Accrued interest (Note 13)									23			31
Long-term accounts payable and other long-term liabilities									(9)			8
Post-retirement and post-employment benefit liability									64			49
									53			249

45

HYDRO ONE LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2025 and 2024

Capital Expenditures

The following tables reconcile investments in property, plant and equipment and intangible assets and the amounts presented in the consolidated statements of cash flows for the years ended December 31, 2025 and 2024. The reconciling items include net change in accruals, transfers, and capitalized depreciation.

Year ended December 31, 2025 (millions of dollars)															Property, Plant and Equipment			Intangible Assets			Total
Capital investments															(3,289)			(77)			(3,366)
Reconciling items															319			(3)			316
Cash outflow for capital expenditures															(2,970)			(80)			(3,050)

Year ended December 31, 2024 (millions of dollars)															Property, Plant and Equipment			Intangible Assets			Total
Capital investments															(2,968)			(95)			(3,063)
Reconciling items															248			7			255
Cash outflow for capital expenditures															(2,720)			(88)			(2,808)

Capital Contributions

Hydro One enters into contracts governed by the OEB Transmission System Code when a transmission customer requests a new or upgraded transmission connection. The customer is required to make a capital contribution to Hydro One based on the shortfall between the present value of the costs of the connection facility and the present value of revenues. The present value of revenues is based on an estimate of load forecast for the period of the contract with Hydro One. Once the connection facility is commissioned, in accordance with the OEB Transmission System Code, Hydro One will periodically reassess the estimated load forecast which will lead to a decrease, or an increase in the capital contributions from the customer. The increase or decrease in capital contributions is recorded directly to property, plant and equipment in service. In 2025, there were $3 million capital contributions from these assessments (2024 - $2 million).

Supplementary Information

Year ended December 31 (millions of dollars)									2025			2024
Net interest paid									724			643
Income taxes paid									45			35

29.    CONTINGENCIES

Legal Proceedings

Hydro One is involved in various lawsuits and claims in the normal course of business. In the opinion of management, the outcome of such matters will not have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows.

Transfer of Assets

The transfer orders by which the Company acquired certain of Ontario Hydro’s businesses as of April 1, 1999 did not transfer title to some assets located on Reserves (as defined in the Indian Act (Canada)). Currently, the OEFC holds these assets. Under the terms of the transfer orders, the Company is required to manage these assets until it has obtained all consents necessary to complete the transfer of title of these assets to itself. The Company cannot predict the aggregate amount that it may have to pay, either on an annual or one-time basis, to obtain the required consents. In 2025, the Company paid $3 million (2024 - $2 million) in respect of consents obtained for a permit that was issued in favour of the Company which would allow for the transfer of assets. In 2025, the Company recorded $6 million (2024 - $4 million) in respect of annual obligations under existing agreements, which includes assets that continued to be held by OEFC. If the Company cannot obtain the required consents, the OEFC will continue to hold these assets for an indefinite period of time. If the Company cannot reach a satisfactory settlement, it may have to relocate these assets to other locations at a cost that could be substantial or, in a limited number of cases, to abandon a line and replace it with diesel-generation facilities. The costs relating to these assets could have a material adverse effect on the Company’s results of operations if the Company is not able to recover them in future rate orders.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        

46

HYDRO ONE LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2025 and 2024

30.    COMMITMENTS

A summary of Hydro One’s commitments under outsourcing and other agreements due in the next five years and thereafter are as follows:

As at December 31, 2025 (millions of dollars)			Year 1			Year 2			Year 3			Year 4			Year 5			Thereafter
Outsourcing and other agreements			48			47			33			1			1			17

Outsourcing and Other Agreements

On July 31, 2025 Hydro One renewed the agreement for information technology services with Capgemini Canada Inc., with a three year term ending July 31, 2028, and includes an option to extend for two additional one-year terms.

Other Commitments

The following table presents a summary of Hydro One’s other commercial commitments by year of expiry in the next five years and thereafter:

As at December 31, 2025 (millions of dollars)			Year 1			Year 2			Year 3			Year 4			Year 5			Thereafter
Operating Credit Facilities1			—			—			—			—			3,300			—
Letters of credit2			191			—			—			—			—			—
Guarantees3			540			—			—			—			—			—

1 On June 1, 2025, the maturity date for the Operating Credit Facilities was extended to June 1, 2030.

2 Letters of credit consist of $166 million letters of credit related to retirement compensation arrangements, an $18 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 Inc. on behalf of its subsidiaries, as well as $60 million of guarantees provided by Hydro One to ONroute relating to OCN LP (OCN Guarantee) and $5 million relating to Aux Energy Inc.

Retirement Compensation Arrangements

Bank letters of credit have been issued to provide security for Hydro One Inc.’s liability under the terms of a trust fund established pursuant to the supplementary pension plan for eligible employees of Hydro One Inc. The supplementary pension plan trustee is required to draw upon these letters of credit if Hydro One Inc. is in default of its obligations under the terms of this plan. Such obligations include the requirement to provide the trustee with an annual actuarial report as well as letters of credit sufficient to secure Hydro One Inc.’s liability under the plan, to pay benefits payable under the plan and to pay the letter of credit fee. The maximum potential payment is the face value of the letters of credit.

Prudential Support

Purchasers of electricity in Ontario, through the IESO, are required to provide security to mitigate the risk of their default based on their expected activity in the market. The IESO could draw on these guarantees and/or letters of credit if these purchasers fail to make a payment required by a default notice issued by the IESO. The maximum potential payment is the face value of any letters of credit plus the amount of the parental guarantees.

47

HYDRO ONE LIMITED

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2025 and 2024

31.    SEGMENTED REPORTING

The Company has three reportable segments: Transmission, Distribution, and Other. The composition of these segments is described in Note 1 to the consolidated financial statements.

The designation of segments has been based on a combination of regulatory status and the nature of the services provided. Operating segments of the Company are determined based on information used by the Chief Operating Decision Maker (CODM) in deciding how to allocate resources and evaluate the performance of each of the segments. Hydro One’s CODM consists of its Chief Executive Officer and certain members of the executive leadership team. The CODM evaluates segment performance based on income before financing charges, equity income, and income tax expense from continuing operations (excluding certain allocated corporate governance costs) (EBIT). The CODM considers the key components of EBIT to understand the variances to prior period on a quarterly basis and measures them against the Company’s budget and forecast across each of the three segments on a monthly basis in order to properly allocate resources between and within the operating segments.

Year ended December 31, 2025 (millions of dollars)			Transmission			Distribution			Other			Consolidated
Revenues			2,429			6,557			55			9,041
Purchased power			—			4,486			—			4,486
Operation, maintenance and administration			447			661			98			1,206
Depreciation, amortization and asset removal costs			570			529			12			1,111
Income (loss) before financing charges, equity income and income tax expense			1,412			881			(55)			2,238
Capital investments			2,097			1,252			17			3,366

Year ended December 31, 2024 (millions of dollars)			Transmission			Distribution			Other			Consolidated
Revenues			2,269			6,175			40			8,484
Purchased power			—			4,143			—			4,143
Operation, maintenance and administration			475			721			112			1,308
Depreciation, amortization and asset removal costs			554			502			10			1,066
Income (loss) before financing charges, equity income and income tax expense			1,240			809			(82)			1,967
Capital investments			1,860			1,185			18			3,063

Total Assets by Segment:

As at December 31 (millions of dollars)			2025			2024
Transmission			23,630			21,630
Distribution			15,160			14,040
Other			881			1,012
Total assets			39,671			36,682

Total Goodwill by Segment:

As at December 31 (millions of dollars)			2025			2024
Transmission			157			157
Distribution			216			216
Other			5			—
Total goodwill			378			373

All revenues, assets and substantially all costs, as the case may be, are earned, held or incurred in Canada.

32.    SUBSEQUENT EVENTS

Dividends

On February 12, 2026, common share dividends of $200 million ($0.3331 per common share) were declared.

CLLP

On January 2, 2026, Hydro One Networks sold to Walpole Island First Nation an approximate 10% equity interest in CLLP for total consideration of approximately $8 million. Following the completion of the transaction, Hydro One Networks’ equity interest in CLLP was reduced to 70%. On February 2, 2026, Aamjiwnaang First Nation and Chippewas of Kettle & Stony Point First Nation collectively purchased an approximate 20% equity interest in CLLP through an equally-owned Limited Partnership for total consideration of approximately $16 million. Following the completion of the transaction, Hydro One Networks’ equity interest in CLLP was reduced to 50%.

48

HYDRO ONE LIMITED

MANAGEMENT’S DISCUSSION AND ANALYSIS

For the years ended December 31, 2025 and 2024

The following Management’s Discussion and Analysis (MD&A) of the financial condition and results of operations should be read together with the consolidated financial statements and accompanying notes thereto of Hydro One Limited (Hydro One or the Company) for the year ended December 31, 2025 (together, the Consolidated Financial Statements). The Consolidated Financial Statements have been prepared in accordance with United States (U.S.) generally accepted accounting principles (GAAP).

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 year ended December 31, 2025, based on information available to management as of February 12, 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.

All financial information in this MD&A is presented in Canadian dollars, unless otherwise indicated.

CONSOLIDATED FINANCIAL HIGHLIGHTS AND STATISTICS

Year ended December 31 (millions of dollars, except as otherwise noted)															2025			2024			Change
Revenues															9,041			8,484			6.6		%
Purchased power															4,486			4,143			8.3		%
Revenues, net of purchased power1															4,555			4,341			4.9		%
Operation, maintenance and administration (OM&A) costs															1,206			1,308			(7.8		%)
Depreciation, amortization and asset removal costs															1,111			1,066			4.2		%
Financing charges															679			621			9.3		%
Income tax expense															219			181			21.0		%
Net income attributable to common shareholders of Hydro One															1,339			1,156			15.8		%
Basic earnings per common share (EPS)															$2.23			$1.93			15.5		%
Diluted EPS															$2.23			$1.92			16.1		%
Net cash from operating activities															2,695			2,534			6.4		%
Funds from operations (FFO)1															2,630			2,275			15.6		%
Annualized FFO to Net Debt1															14.2		%	13.4		%	0.8		%
Capital investments															3,366			3,063			9.9		%
Assets placed in-service															2,901			2,463			17.8		%
Transmission: Average monthly Ontario 60-minute peak demand (MW)															21,398			20,659			3.6		%
Distribution: Electricity distributed to Hydro One customers (GWh)															33,294			31,523			5.6		%

As at December 31			2025			2024
Net Debt to capitalization ratio1			59.5		%	58.4		%

1     See section “Non-GAAP Financial Measures”.

1

HYDRO ONE LIMITED

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2025 and 2024

OVERVIEW

Through its wholly-owned subsidiary Hydro One Inc., Hydro One is Ontario’s largest electricity transmission and distribution utility. Hydro One owns and operates substantially all of Ontario’s electricity transmission network and is the largest electricity distributor in Ontario by number of customers. The Company’s regulated transmission and distribution operations are owned by Hydro One Inc. Hydro One delivers electricity safely and reliably to approximately 1.5 million customers across the province, and to large industrial customers and municipal utilities. Through its subsidiaries, Hydro One Inc. owns and operates approximately 30,000 circuit kilometres of high-voltage transmission lines and approximately 126,000 circuit kilometres of primary low-voltage distribution lines. Hydro One has three segments: (i) transmission; (ii) distribution; and (iii) other.

For the years ended December 31, 2025 and 2024, Hydro One's segments accounted for the Company's total revenues, as follows:

Year ended December 31			2025			2024
Transmission			27		%	27		%
Distribution			72		%	72		%
Other			1		%	1		%

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 years ended December 31, 2025 and 2024 as follows:

Year ended December 31			2025			2024
Transmission			53		%	52		%
Distribution			46		%	47		%
Other			1		%	1		%

As at December 31, 2025 and 2024, Hydro One’s segments accounted for the Company’s total assets as follows:

As at December 31			2025			2024
Transmission			60		%	59		%
Distribution			38		%	38		%
Other			2		%	3		%

Transmission Segment

Hydro One’s transmission business consists of owning and operating the Company’s transmission system, which accounts for approximately 91% (2024 - 90%) of Ontario’s transmission capacity based on the network component of the revenue requirement2 approved by the Ontario Energy Board (OEB).3 As at December 31, 2025, the Company's transmission business consists of the transmission system operated by Hydro One Inc.'s rate-regulated subsidiaries, Hydro One Networks Inc. (Hydro One Networks), Hydro One Sault Ste. Marie LP (HOSSM), and an approximate 80% (2024 - 100%) interest in Chatham x Lakeshore Limited Partnership (CLLP), an approximate 66% interest in B2M Limited Partnership (B2M LP) and an approximate 55% interest in Niagara Reinforcement Limited Partnership (NRLP). The Company’s approximately 80% interest in CLLP was reduced to approximately 70% in January 2026 and 50% in February 2026. The transmission segment also includes Hydro One Networks’ approximate 48% minority interest in the East-West Tie Limited Partnership (EWT LP) (see section “Other Developments - EWT LP”). The Company’s transmission business is rate-regulated and earns revenues mainly by charging transmission rates that are approved by the OEB.

For the year ended December 31			2025			2024
Electricity transmitted1 (MWh)			145,587,496			140,417,171
Rate base (millions of dollars)			17,256			16,335
Capital investments (millions of dollars)			2,097			1,860
Assets placed in-service (millions of dollars)			1,543			1,431

1 Electricity transmitted represents total electricity transmitted in Ontario by all transmitters.

As at December 31			2025			2024
Transmission lines spanning the province (circuit-kilometres)			30,479			29,935

1 See section “Non-GAAP Financial Measures”.

2 The network component of the revenue requirement is Hydro One’s portion of the transmission revenue requirement attributed to assets that are used for the common benefit of all Hydro One and non-Hydro One customers in the province.

3 Hydro One owns and operates approximately 94% of the transmission system in Ontario based on the total OEB approved revenue requirement.

2

HYDRO ONE LIMITED

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2025 and 2024

Distribution Segment

Hydro One’s distribution business is the largest in Ontario and consists of the distribution systems operated by Hydro One Inc.'s rate-regulated subsidiaries, Hydro One Networks and Hydro One Remote Communities Inc. (Hydro One Remotes). The Company’s distribution business earns revenues mainly by charging distribution rates that are approved by the OEB, as well as amounts to recover the cost of purchased power.

For the year ended December 31			2025			2024
Electricity distributed to Hydro One customers (GWh)			33,294			31,523
Electricity distributed through Hydro One lines (GWh)1			43,283			41,445
Rate base (millions of dollars)			10,788			10,184
Capital investments (millions of dollars)			1,252			1,185
Assets placed in-service (millions of dollars)			1,338			1,017

1 Units distributed through Hydro One lines represent total distribution system requirements and include electricity distributed to consumers who purchased power directly from the Independent Electricity System Operator (IESO).

As at December 31			2025			2024
Distribution lines spanning the province (circuit-kilometres)			126,179			125,533
Distribution customers (number of customers)			1,520,883			1,514,690

Other Segment

Hydro One's other segment consists principally of its telecommunications business, which provides telecommunications support for the Company’s transmission and distribution businesses, as well as certain corporate activities.

The telecommunication business is carried out by Hydro One's wholly-owned subsidiary, Acronym Solutions Inc. (Acronym). In addition to supporting Hydro One's regulated business segments, Acronym offers a comprehensive suite of Information and Communications Technology solutions within a number of categories (including: Internet & Network, Security, Voice & Collaboration, Cloud and Managed Information Technology (IT)) that extend beyond its fibre optic network, in a competitive commercial market. Acronym is not regulated by the OEB, however Acronym is registered with the Canadian Radio-television and Telecommunications Commission as a non-dominant, facilities-based carrier, providing broadband telecommunications services in Ontario with connections to Montreal, Quebec; Buffalo, New York; and Detroit, Michigan.

Hydro One's other segment also includes the deferred tax asset (DTA) which arose from the revaluation of the tax bases of Hydro One’s assets to fair market value when the Company transitioned from the provincial payments in lieu of tax regime to the federal tax regime at the time of the Company’s initial public offering in 2015. As the DTA is not required to be shared with ratepayers, the Company considers it to not be part of the regulated transmission and distribution segment assets, and it is included in the other segment. Furthermore, Hydro One's other segment also includes Aux Energy Inc., a wholly-owned subsidiary that provides energy solutions to commercial and industrial clients, and Ontario Charging Network LP, a wholly-owned subsidiary (2024 - a joint venture) that owns and operates electric vehicle fast charging stations across Ontario under the Ivy Charging Network brand, as well as certain corporate activities, and is not rate-regulated.

3

HYDRO ONE LIMITED

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2025 and 2024

PRIMARY FACTORS AFFECTING RESULTS OF OPERATIONS

Transmission Revenues

Transmission revenues primarily consist of regulated transmission rates approved by the OEB which are charged based on the monthly peak electricity demand across Hydro One’s high-voltage network. Transmission rates are designed to generate revenues necessary to construct, upgrade, extend and support a transmission system with sufficient capacity to accommodate maximum forecasted demand and a regulated return on the Company’s investment. Peak electricity demand is primarily influenced by weather and economic conditions. Transmission revenues also include export revenues associated with transmitting electricity to markets outside of Ontario as well as ancillary revenues associated with providing maintenance services to power generators and from third-party land use.

Distribution Revenues

Distribution revenues primarily consist of regulated distribution rates approved by the OEB, as well as the recovery of purchased power costs. Distribution rates are designed to generate revenues necessary to construct and support the local distribution system with sufficient capacity to accommodate existing and new customer demand and a regulated return on the Company’s investment. Accordingly, distribution revenues are influenced by distribution rates, the cost of purchased power, and the amount of electricity the Company distributes. Distribution revenues also include ancillary distribution service revenues, such as fees related to the joint use of Hydro One’s distribution poles by the telecommunications and cable television industries, as well as miscellaneous revenues such as charges for late payments.

Purchased Power Costs

Purchased power costs are incurred by the distribution business and represent the cost of the electricity purchased by the Company for delivery to customers within Hydro One’s distribution service territory. These costs are comprised of: (i) the wholesale commodity cost of energy; (ii) the Global Adjustment, which is the difference between the guaranteed price and the money the generators earn in the wholesale marketplace; and (iii) the wholesale market service and transmission charges levied by the IESO. Hydro One passes on the cost of electricity that it delivers to its customers, and is therefore not exposed to wholesale electricity commodity price risk.

OM&A

OM&A costs are incurred to support the operation and maintenance of the transmission and distribution systems, and include other costs such as property taxes related to transmission and distribution stations and buildings, and the operation of IT systems. Transmission OM&A costs are required to sustain the Company’s high-voltage transmission stations, lines, and rights-of-way, and include preventive and corrective maintenance costs related to power equipment, overhead transmission lines, transmission station sites, and forestry control to maintain safe distances between line spans and trees. Distribution OM&A costs are required to maintain the Company’s low-voltage distribution system to provide safe and reliable electricity to the Company's residential, small business, commercial, and industrial customers across the province. These include costs related to distribution line clearing and forestry control to reduce power outages caused by trees, line maintenance and repair, land assessment and remediation, as well as issuing timely and accurate bills and responding to customer inquiries.

Hydro One manages its costs through ongoing efficiency and productivity initiatives, while continuing to complete planned work programs associated with the development and maintenance of its transmission and distribution networks.

Depreciation, Amortization and Asset Removal Costs

Depreciation and amortization costs relate primarily to the depreciation of the Company’s property, plant and equipment, and amortization of certain intangible assets and regulatory assets. Asset removal costs consist of costs incurred to remove property, plant and equipment where no asset retirement obligations have been recorded on the balance sheet.

Financing Charges

Financing charges relate to the Company’s financing activities and include interest expense on the Company’s long-term debt and short-term borrowings, as well as gains and losses on interest rate swap agreements, foreign exchange or other similar contracts, net of interest earned on short-term investments. A portion of financing charges incurred by the Company is capitalized to the cost of property, plant and equipment associated with the periods during which such assets are under construction before being placed in-service.

4

HYDRO ONE LIMITED

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2025 and 2024

RESULTS OF OPERATIONS

Net Income

Net income attributable to common shareholders of Hydro One for the year ended December 31, 2025 of $1,339 million is $183 million, or 15.8%, higher than the prior year. Significant influences on the change in net income attributable to common shareholders of Hydro One included:

•higher revenues, net of purchased power,4 resulting from an increase in transmission and distribution revenues due to OEB-approved 2025 rates, as well as higher average monthly peak demand and energy consumption, partially offset by regulatory adjustments including higher earnings sharing in the current period; and

•lower OM&A costs primarily resulting from lower work program expenditures and lower corporate support costs; partially offset by

•higher depreciation, amortization and asset removal costs primarily due to the growth in capital assets as the Company continues to place new assets in-service;

•higher financing charges primarily due to an increase in outstanding long-term debt, partially offset by higher capitalized interest; and

•higher income tax expense, primarily resulting from higher pre-tax earnings, partially offset by higher deductible timing differences.

EPS

EPS was $2.23 for the year ended December 31, 2025, compared to EPS of $1.93 in 2024. The 15.5% increase in EPS was primarily driven by higher earnings year-over-year, as discussed above.

Revenues

Year ended December 31 (millions of dollars, except as otherwise noted)															2025			2024			Change
Transmission															2,429			2,269			7.1		%
Distribution															6,557			6,175			6.2		%
Other															55			40			37.5		%
Total revenues															9,041			8,484			6.6		%
Transmission															2,429			2,269			7.1		%
Distribution revenues, net of purchased power1															2,071			2,032			1.9		%
Other															55			40			37.5		%
Total revenues, net of purchased power1															4,555			4,341			4.9		%
Transmission: Average monthly Ontario 60-minute peak demand (MW)															21,398			20,659			3.6		%
Distribution: Electricity distributed to Hydro One customers (GWh)															33,294			31,523			5.6		%

1 See section “Non-GAAP Financial Measures”.

Transmission Revenues

Transmission revenues increased by 7.1% compared to the year ended December 31, 2024, primarily due to:

•higher average monthly peak demand;

•higher revenues resulting from OEB-approved 2025 rates; and

•CLLP revenues following the in servicing of the transmission line in the fourth quarter of 2024; partially offset by

•regulatory adjustments in the period, including a higher earnings sharing accrual.

Distribution Revenues

Distribution revenues increased by 6.2% compared to the year ended December 31, 2024, primarily due to:

•higher purchased power costs, which are fully recovered from ratepayers and thus net income neutral;

•higher revenues resulting from OEB-approved 2025 rates; and

•higher energy consumption; partially offset by

•regulatory adjustments in the period, including a higher earnings sharing accrual; and

•net income neutral items, including lower revenue of Hydro One Remotes, which is offset in OM&A.

Distribution revenues, net of purchased power,4 increased by 1.9% compared to the same period in the prior year largely due to the factors noted above.

4 See section “Non-GAAP Financial Measures”.

5

HYDRO ONE LIMITED

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2025 and 2024

OM&A Costs

Year ended December 31 (millions of dollars)															2025			2024			Change
Transmission															447			475			(5.9		%)
Distribution															661			721			(8.3		%)
Other															98			112			(12.5		%)
															1,206			1,308			(7.8		%)

Transmission OM&A Costs

Transmission OM&A costs were 5.9% lower than the year ended December 31, 2024, primarily due to:

•severance costs in the prior year;

•lower work program expenditures, including vegetation management and lines maintenance; and

•lower corporate support costs; partially offset by

•higher property taxes; and

•higher asset write-offs.

Distribution OM&A Costs

Distribution OM&A costs were 8.3% lower than the year ended December 31, 2024, primarily due to:

•severance costs in the prior year;

•lower work program expenditures, including environmental and vegetation management;

•lower fuel costs of Hydro One Remotes, which are fully recovered through revenue and therefore net income neutral; and

•lower bad debt expense; partially offset by

•higher asset write-offs.

Other OM&A Costs

Other OM&A costs were 12.5% lower than the year ended December 31, 2024, including lower costs in Acronym primarily due to higher third party service costs in the prior year.

Depreciation, Amortization and Asset Removal Costs

Depreciation, amortization and asset removal costs increased by $45 million, or 4.2%, for the year ended December 31, 2025. This increase was primarily due to growth in capital assets as the Company continues to place new assets in-service, consistent with its ongoing capital investment program.

Financing Charges

Financing charges increased by $58 million, or 9.3%, for the year ended December 31, 2025, primarily due to an increase in outstanding long-term debt, partially offset by higher capitalized interest.

Income Tax Expense

Income taxes are accounted for using the asset and liability method. Current income taxes are recorded based on the income taxes expected to be paid in respect of the current and prior years’ taxable income. Deferred income tax assets and liabilities are recognized for the future tax consequences attributable to temporary differences between the financial statement carrying amounts and the respective tax basis of assets and liabilities including carryforward unused tax losses and credits.

As prescribed by the regulators, the Company recovers income taxes in revenues from ratepayers based on an estimate of current income tax expense in respect of regulated operations. The amounts of deferred income taxes related to regulated operations, which are considered to be more likely-than-not of recovery from, or refund to, ratepayers in future periods are recognized as deferred income tax regulatory assets or liabilities, with an offset to deferred income tax expense. Therefore, the consolidated income tax expense or recovery for the current period is based on the total current and deferred income tax expense or recovery, net of the regulatory accounting offset to deferred income tax expense arising from temporary differences recoverable from or refundable to customers in the future.

Income tax expense was $219 million for the year ended December 31, 2025, compared to $181 million in 2024. The $38 million increase in income tax expense for the year ended December 31, 2025 was primarily attributable to:

•higher pre-tax earnings, partially offset by

•higher deductible timing differences compared to the prior year.

The Company realized an effective tax rate (ETR) of approximately 14.0% for the year ended December 31, 2025 compared to approximately 13.4% realized in 2024. The increase of 0.6% was primarily attributable to the factors noted above.

6

HYDRO ONE LIMITED

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2025 and 2024

SHARE CAPITAL

The common shares of Hydro One are publicly traded on the Toronto Stock Exchange (TSX) under the trading symbol "H". 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 February 12, 2026, Hydro One had 599,781,811 issued and outstanding common shares.

The Company is authorized to issue an unlimited number of preferred shares, issuable in series. As at February 12, 2026, the Company had no preferred shares issued and outstanding.

The number of additional common shares of Hydro One that would be issued if all outstanding awards under the share grant plans and the Long-term Incentive Plan (LTIP) were vested and exercised as at February 12, 2026 was 1,424,325.

Common Share Dividends

In 2025, the Company declared and paid cash dividends to common shareholders as follows:

Date Declared

Record Date

Payment Date

Amount per Share

Total Amount (millions of dollars)

February 19, 2025

March 12, 2025

March 31, 2025

$0.3142

188

May 7, 2025

June 11, 2025

June 30, 2025

$0.3331

200

August 12, 2025

September 10, 2025

September 29, 2025

$0.3331

200

November 12, 2025

December 10, 2025

December 31, 2025

$0.3331

200

788

Following the conclusion of the fourth quarter of 2025, the Company declared a cash dividend to common shareholders as follows:

Date Declared

Record Date

Payment Date

Amount per Share

Total Amount (millions of dollars)

February 12, 2026

March 11, 2026

March 31, 2026

$0.3331

$200

SELECTED ANNUAL FINANCIAL STATISTICS

Year ended December 31 (millions of dollars, except per share amounts)															2025			2024			2023
Revenues															9,041			8,484			7,844
Net income attributable to common shareholders of Hydro One															1,339			1,156			1,085
Basic EPS															$2.23			$1.93			$1.81
Diluted EPS															$2.23			$1.92			$1.81
Dividends per common share declared															$1.31			$1.24			$1.17

As at December 31 (millions of dollars)															2025			2024			2023
Total assets															39,671			36,682			32,852
Total non-current financial liabilities1															18,138			16,393			14,750

1 Total non-current financial liabilities include long-term debt, long-term lease obligations, derivative liabilities, and long-term accounts payable and accruals.

Net Income - 2024 compared to 2023

Net income attributable to common shareholders of Hydro One for the year ended December 31, 2024 of $1,156 million was $71 million, or 6.5%, higher than the prior year. Significant influences on the change in net income attributable to common shareholders included:

•higher revenues, net of purchased power,5 resulting from an increase in transmission and distribution revenues due to OEB-approved 2024 rates, differences in regulatory adjustments recorded in each respective period, and higher energy consumption; and

•lower OM&A costs primarily resulting from lower work program expenditures; partially offset by

•higher depreciation, amortization and asset removal costs primarily due to the growth in capital assets as the Company continues to place new assets in-service;

•higher financing charges primarily due to higher interest on long-term debt as well as higher long-term debt, partially offset by a lower average volume of short-term notes outstanding and a higher capitalized interest; and

•higher income tax expense, adjusted for net income neutral items, primarily due to lower deductible timing differences higher pre-tax earnings.

5 See section "Non-GAAP Financial Measures"

7

HYDRO ONE LIMITED

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2025 and 2024

While net income neutral, year-to-date results were also impacted by the cessation of the OEB-approved recovery of DTA amounts previously shared with ratepayers (DTA Recovery Amounts) on June 30, 2023, which resulted in a decrease in revenue, net of purchased power6 in 2024 that has been offset by lower income tax expense.

EPS - 2024 compared to 2023

EPS was $1.93 for the year ended December 31, 2024, compared to EPS of $1.81 in 2023. The increase in EPS was primarily driven by the impact of higher earnings year-over-year, as discussed above.

QUARTERLY RESULTS OF OPERATIONS

Quarter ended (millions of dollars, except EPS and ratio)			Dec 31, 2025			Sep 30, 2025			Jun 30, 2025			Mar 31, 2025			Dec 31, 2024			Sep 30, 2024			Jun 30, 2024			Mar 31, 2024
Revenues			2,268			2,299			2,066			2,408			2,095			2,192			2,031			2,166
Purchased power			1,287			1,080			899			1,220			1,060			1,047			940			1,096
Revenues, net of purchased power1			981			1,219			1,167			1,188			1,035			1,145			1,091			1,070
Net income attributable to common shareholders			233			421			327			358			200			371			292			293
Basic EPS			$0.39			$0.70			$0.54			$0.60			$0.33			$0.62			$0.49			$0.49
Diluted EPS			$0.39			$0.70			$0.54			$0.60			$0.33			$0.62			$0.49			$0.49
Earnings coverage ratio1			2.8			2.8			2.8			2.8			2.8			2.8			2.8			2.8

1    See section “Non-GAAP Financial Measures”.

Variations in revenues and net income attributable to common shareholders 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

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 years ended December 31, 2025 and 2024:

Year ended December 31 (millions of dollars)															2025			2024			Change
Transmission															1,543			1,431			7.8		%
Distribution															1,338			1,017			31.6		%
Other															20			15			33.3		%
Total assets placed in-service															2,901			2,463			17.8		%

Transmission Assets Placed In-Service

Transmission assets placed in-service increased by $112 million, or 7.8%, during the year ended December 31, 2025, compared to the year ended December 31, 2024, primarily due to:

•timing of assets placed in-service for station refurbishments and replacements, including the Bruce A Transmission Station;

•investments placed in-service in Sault Ste. Marie for the Sault #3 Circuit;

•investments placed in-service for customer connection projects; and

•investments placed in-service at the Orillia Distribution Warehouse; partially offset by

•investments placed in-service for the Chatham to Lakeshore Transmission Line;

•lower volume of line refurbishments and wood pole replacements; and

•investment placed in-service for the Network Management System.

6 See section "Non-GAAP Financial Measures"

8

HYDRO ONE LIMITED

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2025 and 2024

Distribution Assets Placed In-Service

Distribution assets placed in-service increased by $321 million, or 31.6%, during the year ended December 31, 2025, compared to the year ended December 31, 2024, primarily due to:

•higher volume of storm-related asset replacements;

•assets placed in-service for the Advanced Metering Infrastructure (AMI) 2.0 system;

•investments placed in-service for the Orillia Distribution Warehouse and the Orillia Operation Centre;

•investments placed in-service for Ontario’s broadband initiative; and

•timing of assets placed in-service for system capability reinforcement projects; partially offset by

•lower volume of wood pole replacements and line refurbishments;

•timing of investments placed in-service for IT initiatives; and

•assets placed in-service for the Orleans Operation Centre in the prior year.

Capital Investments

The following table presents Hydro One’s capital investments during the years ended December 31, 2025 and 2024:

Year ended December 31 (millions of dollars)															2025			2024			Change
Transmission
Sustaining															1,146			1,284			(10.7		%)
Development															864			467			85.0		%
Other															87			109			(20.2		%)
															2,097			1,860			12.7		%
Distribution
Sustaining															688			561			22.6		%
Development															463			513			(9.7		%)
Other															101			111			(9.0		%)
															1,252			1,185			5.7		%
Other															17			18			(5.6		%)
Total capital investments															3,366			3,063			9.9		%

Total 2025 capital investments of $3,366 million for the year ended December 31, 2025, were $176 million lower than the previously disclosed expected amount of $3,542 million, primarily due to timing and project schedule shifts of capital investments for transmission station refurbishments and equipment replacements.

Transmission Capital Investments

Transmission capital investments increased by $237 million, or 12.7%, during the year ended December 31, 2025 compared to the year ended December 31, 2024, primarily due to:

•investments in the Waasigan Transmission Line Project;

•investments in the St. Clair Transmission Line Project; and

•higher spend on customer connections; partially offset by

•lower volume of station refurbishments and equipment replacements;

•lower volume of line refurbishments and wood pole replacements; and

•investments in the Orillia Distribution Warehouse.

Distribution Capital Investments

Distribution capital investments increased by $67 million, or 5.7%, in the year ended December 31, 2025 compared to the year ended December 31, 2024, primarily due to:

•higher spend on storm-related asset replacements;

•investments in Ontario’s broadband initiative; and

•investments in the AMI 2.0 system; partially offset by

•lower volume of wood pole replacements;

•lower spend on system capability reinforcement projects;

•investments in the Orillia Distribution Warehouse, Orillia Operation Centre and Orleans Operation Centre;

•lower spend on IT initiatives;

•lower volume of work on customer connections; and

•lower volume of polychlorinated biphenyl (PCB) transformer replacements.

9

HYDRO ONE LIMITED

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2025 and 2024

Major Transmission Capital Investment Projects

The following table summarizes the status of significant transmission projects as at December 31, 2025:

Project Name

Location

Type

Anticipated In-Service Date

Estimated Cost1

Capital Cost To Date

(year)

(millions of dollars)

Development Projects:

Centennial Transmission Station2

Southwestern Ontario

New transmission station and   connection

2026

229

185

Waasigan Transmission Line3

Thunder Bay-Atikokan-Dryden   Northwestern Ontario

New transmission line and   station expansion

2027

1,200

539

Holt Transmission Station

Bowmanville Central Ontario

New transmission station and   connection

2027

137

28

St. Clair Transmission Line4

Southwestern Ontario

New transmission line and   station expansion

2027

472

247

Keith Intertie Upgrade

Windsor    Southwestern Ontario

Transmission station upgrade

2028

109

9

Welland Thorold Power Line5

Niagara    Southern Ontario

New transmission line and   station expansion

2029

311

20

Longwood to Lakeshore Transmission Line6

Southwestern Ontario

New transmission line and   station expansion

TBD

TBD

46

Durham Kawartha Power Line7,8

Eastern Ontario

New transmission line and   station expansion

TBD

TBD

24

Northeast Power Line7,8

Northeastern Ontario

New transmission line and   station expansion

TBD

TBD

23

North Shore Link7,8

Northeastern Ontario

New transmission line and   station expansion

TBD

TBD

20

Wawa Timmins Power Line7,8

Northeastern Ontario

New transmission line and   station expansion

TBD

TBD

8

Second Longwood to Lakeshore Transmission Line6

Southwestern Ontario

New transmission line and   station expansion

TBD

TBD

2

Windsor to Lakeshore      Transmission Line6

Southwestern Ontario

New transmission line and   station expansion

TBD

TBD

2

Bowmanville to Parkway      Transmission Line9

Southern Ontario

New transmission line and   station expansion

TBD

TBD

—

Wellington to Preston      Transmission Line10

Southwestern Ontario

New transmission line and new transmission station

TBD

TBD

—

Greenstone Transmission Line

Northwestern Ontario

New transmission line and   station expansion

TBD

TBD

—

Sudbury to Barrie     Transmission Line11

Northern-Central Ontario

New transmission line and   station expansion

TBD

TBD

—

Sustainment Projects:

Middleport Transmission Station      Circuit Breaker Replacement

Middleport   Southwestern Ontario

Station sustainment

2026

184

171

Lennox Transmission Station      Circuit Breaker Replacement

Napanee   Southeastern Ontario

Station sustainment

2026

152

152

Esplanade x Terauley      Underground Cable Replacement

Toronto   Southern Ontario

Line sustainment

2026

117

96

Bridgman Transmission Station      Refurbishment

Toronto   Southern Ontario

Station sustainment

2026

108

93

Bruce A Transmission Station      Switchyard Replacement

Tiverton   Southwestern Ontario

Station sustainment

2027

555

421

Otto Holden Transmission Station      Refurbishment

Mattawa   Northeast Ontario

Station sustainment

2028

128

72

Merivale Transmission Station      Replacement and Upgrades12

Ottawa   Eastern Ontario

Station sustainment and   upgrade

2029

271

178

Synchronous Optical Network      Telecommunication Replacement

Ontario

Telecommunication sustainment

2029

137

16

Essa Transmission Station Circuit       Breaker Replacement

Barrie   Central Ontario

Station sustainment

2030

116

7

1 Estimated costs are presented gross of any potential contribution from external parties.

2 This Project is part of a two-phase project, 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. This phase of the project is anticipated to be in service by the end of 2026. Scope and timing of the second phase, an approximately 20 km, 230 kV double-circuit transmission line from London to St. Thomas, is currently under review.

3 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.

4 The St. Clair Transmission Line Project includes the line and associated facilities.

5 The IESO has recommended a target in-service date of 2029 for the Welland Thorold Power Line.

6 The capital cost to date relates to costs incurred in the development phase of the project. 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 to Lakeshore Transmission Line.

7 The capital cost to date relates to costs incurred in the development phase of the project. The scope and timing of these Northeastern and Eastern Ontario transmission reinforcements are currently under review. The Wawa Timmins Power Line was previously referred to as the Wawa to Porcupine Transmission Line.

8 The IESO has recommended a target in-service date of 2030 for the Wawa Timmins Power Line, and of 2029 for the Northeast Power Line, North Shore Link, and the Durham Kawartha Power Line.

9 The Bowmanville to Parkway Transmission Line was previously referred to as the Bowmanville to Greater Toronto Area Transmission Line.

10The IESO has recommended a target in-service date of 2031 for the Wellington to Preston Transmission Line and the Wellington Transmission Station in the Township of Puslinch. (See Section “Other Developments - Wellington to Preston Line Project”)

11Pertains to the First Sudbury to 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.

12 The coordinated project includes both an asset replacement and station expansion. The anticipated in-service dates are between 2026 to 2029.

10

HYDRO ONE LIMITED

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2025 and 2024

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.

The forecast below does not include offsets associated with the impact of restoration costs associated with a severe storm that began on March 28, 2025 causing significant damage to system infrastructure and outages to customers in the central and eastern regions of the province, with restoration efforts continuing into the second quarter. On April 29, 2025, the Company notified the OEB that it intended to submit a Z-Factor application to seek recovery of costs incurred for this storm. On August 28, 2025, the Company submitted the Z-Factor application. The application seeks recovery of approximately $225 million in storm-related costs, including capital and asset removal costs. The forecast is expected to be updated pending the outcome of that application. The decision regarding the Z-factor application is anticipated to be issued by the OEB in early 2026.

The following tables summarize Hydro One’s annual projected capital investments for 2026 to 2027 by business segment and by category:

By business segment: (millions of dollars)															2026			2027
Transmission1															2,116			1,892
Distribution															1,093			918
Other															39			32
Total capital investments2															3,248			2,842

By category: (millions of dollars)															2026			2027
Sustainment															1,426			1,064
Development1															1,657			1,626
Other3															165			152
Total capital investments2															3,248			2,842

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.

2 Since the first quarter of 2022, the Minister of Energy and Electrification (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 eleven priority transmission lines in Ontario. The future capital investments presented do not include capital expenditures, nor development costs, associated with the following three priority Southwestern Ontario transmission line projects: Longwood to Lakeshore Transmission Line, Second Longwood to Lakeshore Transmission Line, and Windsor to Lakeshore Transmission Line; nor the following four priority Northeastern and Eastern Ontario transmission line projects: North Shore Link, Northeast Power Line, Durham Kawartha Power Line, and Wawa Timmins Power Line (see section “Other Developments - Supporting Critical Transmission Infrastructure in Northeastern and Eastern Ontario”); nor the Bowmanville to Parkway, Greenstone and Barrie to Sudbury Transmission Lines (see section “Affordable Energy Act, 2024 and Ontario Integrated Energy Plan”). Hydro One is currently evaluating the scope and timing of these ten 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.

Year ended December 31 (millions of dollars)												2025			2024
Net cash from operating activities												2,695			2,534
Net cash from financing activities												652			1,233
Net cash used in investing activities												(3,514)			(3,130)
Net change in cash and cash equivalents												(167)			637

Net cash from operating activities

Net cash from operating activities increased by $161 million for the year ended December 31, 2025 compared to the same period in 2024. The increase was impacted by various factors, including the following:

•higher pre-tax earnings; and

•changes in regulatory account balances; partially offset by

•changes in net working capital deficiency primarily attributable to lower unearned revenue related to capital contributions, timing differences in the settlement of receivables, higher receivables from the IESO driven by a higher Ontario Electricity Rebate, partially offset by higher cost of power payable to the IESO due to higher purchased volumes.

11

HYDRO ONE LIMITED

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2025 and 2024

Net cash from financing activities

Net cash from financing activities decreased by $581 million for the year ended December 31, 2025, compared to the same period of 2024. This decrease was impacted by various factors, including the following:

Uses of cash

•the Company repaid $6,170 million of short-term notes in 2025, compared to $2,890 million repaid in 2024.

•the Company repaid $1,150 million of long-term debt in 2025, compared to $700 million repaid in 2024.

•the Company paid common share dividends of $788 million in 2025, compared to dividends of $743 million paid in 2024.

Sources of cash

•the Company received proceeds of $6,070 million from the issuance of short-term notes in 2025, compared to $2,810 million received in 2024.

•the Company issued $2,698 million of long-term debt in 2025, compared to $2,781 million of long-term debt issued in 2024.

Net cash used in investing activities

Net cash used in investing activities for the year ended December 31, 2025 was $384 million higher than the same period of 2024 as a result of the investment in EWT LP (see section “Other Developments - EWT LP”), and higher capital investments. See section “Capital Investments” for comparability of capital investments made by the Company during the year ended December 31, 2025 compared to the prior year.

LIQUIDITY AND FINANCING STRATEGY

Short-term liquidity is provided through FFO,7 Hydro One Inc.’s commercial paper program, and the Company’s consolidated bank credit facilities. Under the commercial paper program, Hydro One Inc. 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 December 31, 2025, Hydro One Inc. had $100 million in commercial paper borrowings outstanding, compared to $200 million outstanding at December 31, 2024. The Company also has committed, unsecured, and revolving credit facilities (Operating Credit Facilities) with a total available balance of $3,300 million as at December 31, 2025. 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, 2025, Hydro One extended the maturity date of the Operating Credit Facilities from 2029 to 2030. No amounts were drawn on the Operating Credit Facilities as at December 31, 2025 or 2024. 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 FFO7 are expected to be sufficient to fund the Company’s operating requirements.

As at December 31, 2025, the Company had long-term debt outstanding in the principal amount of $19,045 million, which included $425 million of long-term debt issued by Hydro One and $18,620 million of long-term debt issued by Hydro One Inc. The majority of long-term debt issued by Hydro One Inc. has been issued under its Medium-Term Note (MTN) Program, as further described below. The Company's total long-term debt consists of notes and debentures that mature between 2026 and 2064, and as at December 31, 2025 had a weighted-average term to maturity of approximately 13.7 years (December 31, 2024 - 13.7 years) and a weighted-average coupon rate of 4.2% (December 31, 2024 - 4.2%).

In February 2024, Hydro One Inc. filed a short form base shelf prospectus in connection with its MTN Program, which expires in March 2026. A new MTN Program prospectus is expected to be filed in the first quarter of 2026.

On August 19, 2024, Hydro One filed a short form base shelf prospectus (Universal Base Shelf Prospectus) with securities regulatory authorities in Canada. The Universal Base Shelf Prospectus allows Hydro One to offer, from time to time in one or more public offerings, debt, equity or other securities, or any combination thereof, during the 25-month period ending in September 2026. As at December 31, 2025, no securities have been issued under the Universal Base Shelf Prospectus.

On November 29, 2024, Hydro One Holdings Limited (HOHL) filed a short form base shelf prospectus (HOHL U.S. Debt Shelf Prospectus) with securities regulatory authorities in Ontario and the U.S., that expires in December 2026. The HOHL U.S. Debt Shelf Prospectus allows HOHL to offer, from time to time in one or more public offerings, debt securities, unconditionally guaranteed by Hydro One. As at December 31, 2025, no securities have been issued under the HOHL U.S. Debt Shelf Prospectus.

7 See section “Non-GAAP Financial Measures”.

12

HYDRO ONE LIMITED

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2025 and 2024

On August 18, 2025, Hydro One Inc. 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 Inc. 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 December 31, 2025, no securities have been issued under the HOI U.S. Debt Shelf Prospectus.

Compliance

As at December 31, 2025, the Company was in compliance with all financial covenants and limitations associated with the outstanding borrowings and credit facilities.

Credit Ratings

Various ratings organizations review the Company’s and Hydro One Inc.’s debt ratings from time to time. These rating organizations may take various actions, positive or negative. The Company cannot predict what actions rating agencies may take in the future. The failure to maintain the Company’s current credit ratings could adversely affect the Company’s financial condition and results of operations, and a downgrade in the Company’s credit ratings could restrict the Company’s ability to access debt capital markets and increase the Company’s cost of debt.

As at December 31, 2025, Hydro One’s long-term debt ratings were as follows:

Rating Agency						Long-term Debt Rating
DBRS Limited						A
S&P Global Ratings						A-

As at December 31, 2025, Hydro One Inc.’s long-term and short-term debt ratings were as follows:

Rating Agency			Short-term Debt Rating			Long-term Debt Rating
DBRS Limited			R-1 (low)			A (high)
Moody’s Ratings			Prime-2			A3
S&P Global Ratings			A-1 (Mid)			A

Effect of Interest Rates

The Company is exposed to fluctuations of interest rates as its regulated return on equity (ROE) is derived using a formulaic approach that takes into account changes in benchmark interest rates for Government of Canada debt and the A-rated utility corporate bond yield spread. The Company issues debt from time to time to refinance maturing debt and for general corporate purposes. The Company is therefore exposed to fluctuations in interest rates in relation to such issuances of debt. See section “Risk Management and Risk Factors - Risks Relating to Hydro One’s Business - Market, Financial Instrument and Credit Risk” for more details.

Pension Plan

In 2025, Hydro One made cash contributions of $68 million to its pension plan, compared to cash contributions of $75 million in 2024. The Company also incurred $124 million of net periodic benefit credit, compared to $57 million of net periodic benefit credit incurred in 2024.

In September 2025, Hydro One filed a triennial actuarial valuation of its pension plan as at December 31, 2024 which is effective for 2025 to 2027. Based on this valuation, Hydro One estimates that total Company pension contributions for 2026, 2027, 2028, 2029 and 2030 are approximately $70 million, $73 million, $77 million, $81 million, and $85 million, respectively. Future minimum contributions beyond 2027 will be updated following the actuarial funding valuation as of December 31, 2027, which is expected to be filed by no later than September 30, 2028. Should Hydro One elect to file a valuation earlier than required, contributions for 2027 would also be updated, as applicable.

The Company’s pension benefits obligation is impacted by various assumptions and estimates, such as the discount rate, rate of return on plan assets, rate of cost of living increase and mortality assumptions. A full discussion of the significant assumptions and estimates can be found in the section “Critical Accounting Estimates - Employee Future Benefits”.

13

HYDRO ONE LIMITED

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2025 and 2024

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 December 31, 2025 (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 repayments			19,045			925			1,175			1,900			15,045
Long-term debt - interest payments			11,444			792			1,526			1,399			7,727
Short-term notes payable			100			100			—			—			—
Pension contributions1			386			70			150			166			—
Outsourcing and other agreements			147			48			80			2			17
Environmental and asset retirement obligations			104			10			8			17			69
Lease obligations			45			16			24			4			1
Total contractual obligations			31,271			1,961			2,963			3,488			22,859
Other commercial commitments (by year of expiry)
Operating Credit Facilities			3,300			—			—			3,300			—
Letters of credit2			191			191			—			—			—
Guarantees3			540			540			—			—			—
Total other commercial commitments			4,031			731			—			3,300			—

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, an $18 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 Inc. on behalf of its subsidiaries, as well as $60 million of guarantees provided by Hydro One to ONroute relating to OCN LP (OCN Guarantee) and $5 million relating to Aux Energy Inc.

14

HYDRO ONE LIMITED

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2025 and 2024

REGULATION

The following table summarizes the key elements and status of Hydro One’s electricity rate applications:

Application			Year			Rate Base Approved/Proposed (millions of dollars)			Base Revenue Requirement Approved/Proposed (millions of dollars)			Status
Transmission:
Hydro One Networks1			2025			16,271			2,168			Approved in November 2022
			2026			17,148			2,277			Approved in November 2022
			2027			17,940			2,362			Approved in November 2022
B2M LP			2025			455			38			Approved in November 2024
			2026			447			38			Approved in October 20252
			2027			440			39			Approved in October 20252
			2028			433			39			Approved in October 20252
			2029			426			37			Approved in October 20252
HOSSM3			2017-2026			218			41			Approved in January 2016
CLLP			2025			201			17			Approved in November 2024
			2026			209			17			Approved in December 20252
			2027			206			16			Approved in December 20252
			2028			204			16			Approved in December 20252
			2029			201			16			Approved in December 20252
NRLP			2025			110			9			Approved in November 2024
			2026			108			9			Approved in October 20252
			2027			107			9			Approved in October 20252
			2028			105			9			Approved in October 20252
			2029			104			9			Approved in October 20252
Distribution:
Hydro One Networks1			2025			10,573			1,886			Approved in November 2022
			2026			11,153			1,985			Approved in November 2022
			2027			11,656			2,071			Approved in November 2022
Hydro One Remotes4			2023-2027			58			128			Approved in March 2023

1 Revenue requirements for 2025 to 2027 do not include the impacts of updates filed with the regulator per the annual application process to reflect the latest OEB inflation factors.

2 Under the agreed-upon revenue requirement framework, there is no longer a requirement for these LPs to file annual update applications with the OEB throughout the rate term, except for the one-time update in 2025.

3 HOSSM is under a 10-year deferred rebasing period for years 2017-2026, as approved in the OEB Mergers, Amalgamations, Acquisitions and Divestitures decision dated October 13, 2016. Revenue requirement since 2019 have been subject to an approved revenue cap escalator index.

4 Revenue requirements for 2025 to 2027 will be updated per the annual application process with the regulator to reflect latest OEB inflation factors. Rate increases for Hydro One Remotes are effective May 1st of each year.

The following table summarizes the status of Hydro One’s Leave to Construct Applications with the OEB for significant transmission projects as at December 31, 2025:

Application						Status
Welland Thorold Power Line Project						Filed in November 20251
Waasigan Transmission Line Project						Approved in April 20241
St. Clair Transmission Line Project						Approved in December 20242

1 See section “Major Transmission Capital Investment Projects” and “Other Developments - Welland Thorold Power Line”. Under Hydro One’s equity partnership model, First Nations communities would have an opportunity to acquire a 50% equity stake in the transmission line component of the project.

2 See section “Major Transmission Capital Investment Projects” and “Other Developments - Supporting Critical Infrastructure in Southwestern Ontario.” Under Hydro One’s equity partnership model, First Nations communities would have an opportunity to acquire a 50% equity stake in the transmission line component of the project.

15

HYDRO ONE LIMITED

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2025 and 2024

OEB Cost of Capital Policy Review

On March 6, 2024, the OEB commenced a hearing on its own motion to consider the methodology for determining the values of the cost of capital parameters and deemed capital structure to be used in the rate-setting process, as well as the methodology for determining the OEB’s prescribed interest rates and matters related to the Incremental Cloud Computing Implementation Costs deferral account, including what type of interest rate, if any, should apply to the account. On March 27, 2025, the OEB issued its Decision and Order, issuing new cost of capital parameters and confirming that the new cost of capital parameters will take effect at a utility’s next rebasing rate application. The OEB’s approach for deemed capital structure remained unchanged at 40% equity and 60% debt, for transmission and distribution electricity utilities. The OEB also concluded that the prescribed interest rate for deferral and variance accounts will continue to apply to the Incremental Cloud Computing Implementation Costs deferral account, and that each utility, in its next rebasing rate application, can propose the treatment of any future cloud solutions during the rate term, which could include a new cloud solution deferral account. If no proposal is made during that rebasing rate application, the account will be closed.

Extended Horizons Variance Account

On March 20, 2025, the OEB established a generic deferral and variance account, effective November 18, 2024. This variance account allows rate-regulated electricity distributors to record the incremental revenue requirement impacts resulting from reductions in the forecasted customer capital contributions embedded in distribution rates related to the OEB’s amendments to the Distribution System Code in December 2024, which extend the connection horizon and revenue horizon for certain customer connections. As at December 31, 2025, the balance in the account is immaterial.

B2M LP

On May 23, 2024, Hydro One Networks, on behalf of B2M LP, submitted B2M LP’s five-year Transmission Revenue Requirement Application for the 2025 to 2029 period. On November 21, 2024, the OEB issued a Decision and Order approving B2M LP’s five-year revenue requirement application, which includes a 2025 base revenue requirement of $38 million. Under the agreed-upon revenue requirement framework, there is no longer a requirement for B2M LP to file annual update applications with the OEB throughout the rate term, except for a one-time update in 2025, which the OEB approved in October 2025, setting the revenue requirements for 2026-2029.

NRLP

On May 23, 2024, Hydro One Networks, on behalf of NRLP, submitted NRLP’s five-year Transmission Revenue Requirement Application for the 2025 to 2029 period. On November 21, 2024, the OEB issued a Decision and Order approving NRLP’s revenue requirement application, which includes a 2025 base revenue requirement of $9 million. Under the agreed-upon revenue requirement framework, there is no longer a requirement for NRLP to file annual update applications with the OEB throughout the rate term, except for a one-time update in 2025, which the OEB approved in October 2025, setting the revenue requirements for 2026-2029.

CLLP

On July 12, 2024, Hydro One Networks, on behalf of CLLP, submitted CLLP’s five-year Transmission Revenue Requirement Application for the 2025 to 2029 period. On December 17, 2024, the OEB issued a Decision and Order approving CLLP’s revenue requirement application, which includes a 2025 base revenue requirement of $17 million, effective January 1, 2025. Under the agreed-upon revenue requirement framework, there is no longer a requirement for CLLP to file annual update applications with the OEB throughout the rate term, except for a one-time update in 2025, which the OEB approved in December 2025, setting the revenue requirements for 2026-2029.

Building Broadband Faster Act, 2021

In March 2021, the Province of Ontario (Province) introduced Bill 257, Supporting Broadband and Infrastructure Expansion Act, 2021, to create a new act entitled the Building Broadband Faster Act, 2021 (BBFA) that is aimed at supporting the timely deployment of broadband infrastructure within unserved and underserved rural Ontario communities. Bill 257 received Royal Assent on April 12, 2021. Bill 257 amended the Ontario Energy Board Act, 1998 (OEBA) to provide the Province with regulation-making authority regarding the development of, access to, or use of electricity infrastructure for non-electricity purposes. The BBFA Guideline and two regulations informing the legislative changes were also published in 2021, with a third regulation on annual wireline attachment rate for telecommunications carriers issued in December 2021. The most recent Order and Decision from the OEB adjusts the annual wireline attachment rate to $39.14 per attacher per pole, effective January 1, 2025.

In March 2022, the Province introduced Bill 93 (Getting Ontario Connected Act, 2022). Bill 93 received Royal Assent on April 14, 2022. Bill 93 amends the BBFA to ensure that organizations that own underground utility infrastructure near a designated high-speed internet project provide timely access to their infrastructure data, which would allow internet service providers to quickly start work on laying down underground high-speed internet infrastructure.

A regulation regarding electricity infrastructure and designated broadband projects under the OEBA (O.Reg. 410/22) came into force on April 21, 2022. On July 7, 2022, the OEB established a deferral account for rate-regulated distributors to record incremental costs associated with carrying out activities pertaining to designated broadband projects. In September 2022, the

16

HYDRO ONE LIMITED

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2025 and 2024

Company launched its choice-based operating model to provide internet service providers with choices on how to access the Company’s infrastructure in order to effectively execute designated broadband projects. On March 28, 2023, the Province amended the OEBA (O.Reg. 410/22) with respect to performance timelines associated with designated broadband projects.

On August 14, 2023, the third edition of the BBFA Guideline was issued with amendments providing additional guidance to support the implementation of legislative and regulatory requirements, including a framework to support cost sharing for pole attachments and make-ready work.

The Company has developed and adapted an appropriate management framework that meets the government’s objectives, including arrangements to sustain the Company’s revenues and recovery of reasonable associated costs.

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 November 1, 2025, the Province amended a regulation made under the OEBA (O.Reg. 410/22), implementing a monthly capacity target of poles ready for deployment and extending the performance timelines associated with the designated broadband projects. Hydro One Networks must complete its share of the work before July 1, 2028.

Affordable Energy Act, 2024 and Ontario Integrated Energy Plan

In January 2024, the Electrification and Energy Transition Panel, an advisory body to the Province, released its report outlining a roadmap for Ontario’s transition to a clean energy economy. In October 2024, the Province released its vision for Ontario’s energy sector, Ontario’s Affordable Energy Future, outlining key objectives to meet growing electricity demand in Ontario. This vision was intended to help guide the Province’s first integrated energy plan (IEP), among other initiatives. In support, Bill 214, Affordable Energy Act, 2024, was introduced and subsequently received Royal Assent on December 4, 2024. The Affordable Energy Act, 2024 amended various statutes, including the Electricity Act, 1998 (Ontario) (Electricity Act) and the OEBA, providing a legislative framework to replace the Province’s long-term energy plans (including the 2017 Long-Term Energy Plan), with integrated energy plans. Whereas the focus of the long-term energy plan had been primarily on the electricity system, the integrated energy plan is intended to address all sources of energy. The amendments effected by the Affordable Energy Act, 2024 also allow the Minister, subject to the approval of the Lieutenant Governor in Council, to issue directives to the IESO and OEB setting out implementation requirements relating to the integrated energy plan. From October to December 2024, the Ministry of Energy and Mines (Ministry) (formerly the Ministry of Energy and Electrification) ran a consultation requesting feedback to assist the Province in developing its first plan.

The changes made by the Affordable Energy Act, 2024 to the OEBA, among other things, also provide the Province with the ability to make regulations specifying amendments to the Distribution System Code and the Transmission System Code in relation to certain cost allocation and cost recovery matters relating to the construction, expansion or reinforcement of distribution systems or transmission systems, or of connections to those systems. The changes made by the Affordable Energy Act, 2024 also allow regulations to be made exempting persons or things from provisions of the Distribution System Code and the Transmission System Code relating to cost allocation or cost recovery, as well as alternative provisions that apply instead.

On June 12, 2025, the Ontario government released its first 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 the following:

•Barrie to Sudbury Transmission Line, a new single circuit 500 kV line between Essa Transformer Station (TS) and Hanmer TS, including any associated station facilities with a target in-service date of 2032, as well as early development work on a second 500 kV line;

•Orangeville to Barrie Reconductoring Project, which involves the reconductoring of Hydro One’s existing 230kV transmission lines between Orangeville TS (Orangeville) and Essa TS (Barrie), with a target in-service date of 2027;

•Bowmanville to Parkway Transmission Line (formerly known as Bowmanville to Greater Toronto Area (GTA) Transmission Line), a new double-circuit 500 kV line from Bowmanville Switching Station (SS) to an existing 500 kV station in the GTA with a target in-service in the early 2030s;

•Windsor to Lakeshore Transmission Line, a 230 kV transmission line from Lauzon Transformer Station (Windsor) to Lakeshore Transformer Station (Lakeshore) with a target in-service date of 2032; and

•Greenstone Transmission Line, a new 230 kV transmission line between Longlac TS (Geraldton) to Nipigon Generation Station and connecting into the East-West Tie near Nipigon Bay, and associated station facilities, with a target in-service in 2032.

17

HYDRO ONE LIMITED

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2025 and 2024

On June 16, 2025, the Ministry announced a series of proposals to take certain actions to facilitate the timely development of several transmission projects to further the objectives outlined in the IEP.

The Ministry proposed, subject to required approvals, to declare the five transmission projects as priority projects. The second Barrie to Sudbury Transmission Line was not proposed to be declared priority at the time.

The Ministry also proposed to bring forward Orders in Council (to be recommended by the Minister of Energy and Mines (Minister)) and 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 Barrie to Sudbury Transmission Line, the Bowmanville to Parkway Transmission Line and the Greenstone Transmission Line, and to undertake development work on the second Barrie to Sudbury Transmission Line. The Minister had previously, on March 31, 2022, directed the OEB to amend Hydro One Networks’ licence to require it to develop and seek approvals for the Windsor to Lakeshore Transmission Line. The Orangeville to Barrie Reconductoring Project does not require designation because this project relates to existing Hydro One Networks transmission infrastructure. The consultation period for the proposals was announced on June 16, 2025, and closed on August 15, 2025.

On November 21, 2025, the Minister notified the OEB that the Orangeville to Barrie Reconductoring Project, the Windsor to Lakeshore Transmission Line and the Bowmanville to Parkway Transmission Line 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 Bowmanville to Parkway Transmission Line. On November 25, 2025, further to the Minister’s Directive, the OEB amended Hydro One Networks’ electricity transmission licence to allow it to develop and seek approvals for this project in accordance with the recommendations of the IESO.

On January 28, 2026, the Minister notified the OEB that the Greenstone Transmission Line was declared a priority project, and issued a directive to the OEB to amend Hydro One Networks’ transmission license, to require it to develop and seek approvals for this project. On January 29, 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 this project in accordance with the recommendations of the IESO.

On February 6, 2026, the Minister notified the OEB that the first Barrie to Sudbury Transmission Line was declared a priority project, and issued a directive to the OEB to amend Hydro One Networks’ transmission license to require it to develop and seek approvals for both Barrie to Sudbury Transmission Lines, and to undertake development work on the second Barrie to Sudbury Transmission Line. On February 10, 2026, further to the Minister’s Directive, the OEB amended Hydro One Networks’ electricity transmission licence to allow it to develop and seek approvals for the project in accordance with the recommendations of the IESO.

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 one double-circuit 230 kV transmission line that will run from Dryden TS to Ear Falls TS, and another double-circuit 230-kV transmission line that will run from Ear Falls TS to Red Lake SS, along with associated station facilities, to meet growing capacity needs after 2028. Hydro One will work with the IESO to identify the earliest achievable in-service date for the project. On October 29, 2025, the Ministry announced a proposal to bring forward an Order in Council (to be recommended by the Minister) to declare the project 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 project. The consultation period for the proposal closed on December 13, 2025.

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 Networks intends to submit an application to be included in the TSF Registry.

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.

18

HYDRO ONE LIMITED

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2025 and 2024

Northern Ontario Voltage Study

In December 2023, the IESO published its Northern Ontario Voltage Study Report (Bulk System Reactive Requirements in Northern Ontario) (the Study), which recommended installation of reactive compensation devices at several stations in Northern Ontario to address both current and future system conditions that are expected once new Northern transmission lines are in-service. This study includes projects being developed by Hydro One, including: the East-West Tie Station Expansion, the Waasigan Transmission Line Project, the Northeast Power Line (previously referred to as the Hanmer to Mississagi Line), and the North Shore Link (previously referred to as Mississagi to Third Line Line).

In March 2024, the Company received a letter from the IESO recommending Hydro One proceed with the implementation of the reactive devices, in line with the timelines identified by the IESO. The Company has reviewed and assessed the results of the Study and recommendation from the IESO and has incorporated them into the associated projects so as to meet the timelines identified by the IESO.

Supporting Critical Transmission Infrastructure in Southwestern Ontario

St. Clair Transmission Line Project

In March 2022, the Province issued an Order in Council with a directive from the Minister (formerly the Minister of Energy) to the OEB, requiring Hydro One Networks to develop and seek approvals for the St. Clair Transmission Line Project, a 230 kV line from Lambton Transmission Station to Chatham Switching Station. In response to the directive, the OEB amended Hydro One Networks’ transmission license in April 2022 to develop and seek approval for the St. Clair Transmission Line Project. On May 28, 2024, Hydro One Networks filed a leave-to-construct application seeking OEB approval of the project. The total project is expected to cost approximately $472 million, with $335 million attributable to transmission line work and $137 million attributable to station costs. On December 10, 2024, the OEB issued its Decision and Order granting leave to construct as requested in the application, with standard conditions of approval.

On September 9, 2025, Hydro One commenced the construction of the St. Clair Transmission Line Project, which is expected to be in service by 2027.

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 transmission projects across Northeastern and Eastern Ontario: North Shore Link, Northeast Power Line, and 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 these three priority transmission line 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 these projects in accordance with the recommendations of the IESO.

On August 1, 2024, the Ministry announced a proposal to declare the Wawa Timmins Power Line (formerly Wawa to Porcupine line) as a priority project and designate Hydro One Networks, as the transmitter. These actions are intended to facilitate the timely development of a new 230 kV, 260 km transmission line in Northeastern Ontario from the Wawa Transformer Station (south of Wawa) to the Porcupine Transformer Station (Timmins area). Based on IESO forecasts, the government has identified a targeted in-service date of 2030; planned development work will inform the final construction schedule. The proposal was open for a 45 day consultation period ending September 15, 2024. On November 28, 2024, the Minister directed the OEB to amend Hydro One Networks’ transmission license to require it to develop and seek approvals for this project. On December 23, 2024, further to the Minister’s Directive, the OEB amended Hydro One Networks’ electricity transmission licence to allow it to develop and seek approvals for this project in accordance with the recommendations of the IESO.

Wellington to Preston Line Project

As part of its integrated regional resource plan process for the Kitchener-Waterloo-Cambridge-Guelph Region, on September 29, 2025 the IESO, in conjunction with a technical working group (working group), issued a letter to Hydro One Networks with respect to an urgent need for certain transmission infrastructure. As part of the letter, the IESO identified the following two investments for Hydro One to complete:

•Development and initiating construction of a new 500/230 kV autotransformer station in Puslinch, with a target in-service date of 2031; and

•Development and initiating construction of a new 230 kV transmission line from Puslinch to Preston TS, with a target in-service date of 2031.

The IESO and the working group recommend that Hydro One proceed immediately with development of these projects, including pursuing the required environmental and regulatory approvals.

19

HYDRO ONE LIMITED

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2025 and 2024

Welland Thorold Power Line

The IESO’s 2022 integrated regional resource plan (IRRP) for the Niagara region identified growing electricity demand in the Welland area. To support this projected increase, the IRRP recommended enhancing transmission capacity through the development of a new transmission line. This need was subsequently reaffirmed in the 2023 Regional Infrastructure Plan. On November 17, 2025, Hydro One Networks filed a leave-to-construct application seeking OEB’s approval for the Welland to Thorold Power Line, a new double-circuit 230-kilovolt transmission line between Abitibi Consolidated Junction, within an existing Hydro One transmission corridor in Thorold and Crowland TS in Welland. In addition to the line work, Hydro One will also expand Crowland TS. See section "Major Transmission Capital Investment Projects” for additional information.

Bill 2, Protect Ontario Through Free Trade Within Canada Act, Bill 5, Protect Ontario by Unleashing our Economy Act, and Bill 40, Protect Ontario by Securing Affordable Energy for Generations Act

On April 16, 2025, the Ontario Government introduced Bill 2, Protect Ontario Through Free Trade Within Canada Act, 2025. The legislation enables the province to, among other things, enter into mutual recognition agreements with other provinces to remove internal trade barriers in the movement of goods, services, and labour.

On April 17, 2025, the Ontario Government introduced Bill 5, the Protect Ontario by Unleashing our Economy Act, which aims to streamline the permitting and authorization process for certain projects, including major infrastructure, including through proposed changes to the environmental permitting process in Ontario.

On June 3, 2025, the Ontario Government introduced Bill 40, Protect Ontario by Securing Affordable Energy for Generations Act, 2025. The legislation enables the establishment of variance accounts for foreign equipment restrictions and introduces regulation-making authority with regards to data centre connections in Ontario.

Bill 2 and Bill 5 received Royal Assent on June 5, 2025. Bill 40 received Royal Assent on December 11, 2025. The Company is assessing the potential impacts of this legislation and associated regulations on Hydro One.

Sustainability Report

The Hydro One 2024 Sustainability Report entitled “A Better and Brighter Future For All” is available on the Company’s website at www.hydroone.com/sustainability.

The 2024 Sustainability Report highlights the alignment of sustainability with Hydro One’s refreshed corporate strategy to enable the Company to continue to deliver for its customers and all Ontarians. The report discloses the Company’s performance across a range of environmental, social and governance (ESG) measures from January 1, 2024 to December 31, 2024.

HYDRO ONE BOARD OF DIRECTORS AND EXECUTIVE OFFICERS

Board of Directors

Effective March 24, 2025, Timothy Hodgson, then chair of the Board, commenced an unpaid leave of absence to pursue candidacy in the federal election. The board appointed Susan Wolburgh Jenah as Interim Chair on the same date.

On April 28, 2025, Mr. Hodgson formally resigned from the Board. Subsequently, the Board appointed Melissa Sonberg as chair of the Board, with the appointment taking effect on June 4, 2025.

Director Cherie Brant did not stand for re-election at the Annual and Special Meeting of Shareholders on June 24, 2025.

Effective August 14, 2025, the Board appointed Michael W. Rencheck as a director.

Executive Officers

Effective February 18, 2025, Gillian Whitebread joined Hydro One as Executive Vice President (EVP), Head of Human Resources. On the same day, Megan Telford’s title became EVP, Strategy and Energy Transition.

Effective July 21, 2025, Megan Telford was appointed as Chief Operating Officer, and Lisa Pearson was appointed as EVP, Corporate Affairs.

Effective August 25, 2025, David Lebeter commenced a temporary compassionate care leave. The Board selected Harry Taylor to become the Interim President and Chief Executive Officer (CEO). Harry Taylor continued to serve as EVP, Chief Financial and Regulatory Officer during the interim period. David Lebeter returned from leave on November 12, 2025.

20

HYDRO ONE LIMITED

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2025 and 2024

HYDRO ONE WORK FORCE

As at December 31, 2025, Hydro One had a skilled and flexible work force of approximately 7,200 (2024 - 7,300) regular employees and 1,900 (2024 - 2,100) non-regular employees province-wide, comprising a mix of skilled trades, engineering, professional, managerial and executive personnel. Hydro One’s regular employees are supplemented primarily by accessing a large external labour force available through arrangements with the Company’s trade unions for contingent workers, sometimes referred to as “hiring halls”, and also by access to contract personnel. The hiring halls offer Hydro One the ability to flexibly use highly trained and appropriately skilled workers on a project-by-project and seasonal basis.

The following table sets out the number of Hydro One employees as at December 31, 2025:

			Regular Employees			Non-Regular Employees			Total
Power Workers' Union (PWU)1			4,201			626			4,827
Society of United Professionals (Society)			2,020			29			2,049
Canadian Union of Skilled Workers (CUSW) and construction building trade unions			—			1,270			1,270
Total employees represented by unions			6,221			1,925			8,146
Management and non-represented employees			930			22			952
Total employees2			7,151			1,947			9,098

1 Includes 510 non-regular “hiring hall” employees covered by the PWU agreement.

2    The average number of Hydro One employees in 2025 was approximately 9,600, consisting of approximately 7,200 regular employees and approximately 2,400 non-regular employees.

Collective Agreements

On May 4, 2025, Hydro One Inc. reached tentative renewal agreements with the PWU for both its main collective agreement and its Customer Service Operations (CSO) collective agreement which merges the two agreements into one. On June 2, 2025, the agreement was ratified by the PWU-represented employees for a term from October 1, 2025, to March 31, 2028.

Hydro One Inc.’s collective agreement with the Society expired on September 30, 2025. On January 13, 2026, Hydro One and the Society announced that a settlement for a renewal collective agreement had been reached. On January 30, 2026, the Society-represented employees ratified the collective agreement, with a term of October 1, 2025 to March 31, 2028.

The construction building trade unions have collective agreements with the Electrical Power Systems Construction Association (EPSCA). EPSCA is an employers’ association of which Hydro One is a member. All 20 of the EPSCA construction collective agreements, which bind Hydro One, expired on April 30, 2025. EPSCA negotiated five-year renewal agreements, covering the period from May 1, 2025 to April 30, 2030, for all 20 collective agreements.

Stock-based Compensation

The Company granted Deferred Share Units (DSUs) and LTIP awards, consisting of Performance Share Units (PSUs) and Restricted Share Units (RSUs) to Directors and Management. As at December 31, 2025 and 2024, the following LTIP and other awards were outstanding:

As at December 31 (number of units)						2025			2024
PSUs						399,181			286,554
RSUs						391,623			322,925
Management DSUs						80,404			85,690
Director DSUs						102,256			107,296

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.

21

HYDRO ONE LIMITED

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2025 and 2024

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 common shareholders. 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.

Quarter ended (millions of dollars)			Dec 31, 2025			Sep 30, 2025			Jun 30, 2025			Mar 31, 2025			Dec 31, 2024			Sep 30, 2024			Jun 30, 2024			Mar 31, 2024
Net cash from operating activities			867			713			605			510			703			623			746			462
Changes in non-cash balances related to operations			(214)			(31)			14			178			(190)			18			(221)			144
Distributions to noncontrolling interest			(1)			(4)			(2)			(5)			(2)			(2)			(2)			(4)
FFO			652			678			617			683			511			639			523			602

Twelve months ended (millions of dollars)

Dec 31, 2025

Dec 31, 2024

FFO

2,630

2,275

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)			Dec 31, 2025			Sep 30, 2025			Jun 30, 2025			Mar 31, 2025			Dec 31, 2024			Sep 30, 2024			Jun 30, 2024			Mar 31, 2024
Revenues			2,268			2,299			2,066			2,408			2,095			2,192			2,031			2,166
Less: Purchased power			1,287			1,080			899			1,220			1,060			1,047			940			1,096
Revenues, net of purchased power			981			1,219			1,167			1,188			1,035			1,145			1,091			1,070

Quarter ended (millions of dollars)			Dec 31, 2025			Sep 30, 2025			Jun 30, 2025			Mar 31, 2025			Dec 31, 2024			Sep 30, 2024			Jun 30, 2024			Mar 31, 2024
Distribution revenues			1,757			1,605			1,434			1,761			1,583			1,551			1,436			1,605
Less: Purchased power			1,287			1,080			899			1,220			1,060			1,047			940			1,096
Distribution revenues, net of purchased power			470			525			535			541			523			504			496			509

Year ended December 31 (millions of dollars)												2025			2024
Revenues												9,041			8,484
Less: Purchased power												4,486			4,143
Revenues, net of purchased power												4,555			4,341

Year ended December 31 (millions of dollars)												2025			2024
Distribution revenues												6,557			6,175
Less: Purchased power												4,486			4,143
Distribution revenues, net of purchased power												2,071			2,032

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.

Year ended December 31 (millions of dollars)									2025			2024
Short-term notes payable									100			200
Less: cash and cash equivalents									(549)			(716)
Long-term debt (current portion)									925			1,150
Long-term debt (long-term portion)									18,092			16,329
Net Debt									18,568			16,963

22

HYDRO ONE LIMITED

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2025 and 2024

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.

Year ended December 31 (millions of dollars)									2025			2024
Net debt (A)									18,568			16,963
Shareholders' equity (excluding noncontrolling interest)									12,648			12,089
Net debt plus shareholders' equity (B)									31,216			29,052

Net Debt-to-capitalization ratio (A/B) 59.5 % 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)			Dec 31, 2025			Sep 30, 2025			Jun 30, 2025			Mar 31, 2025			Dec 31, 2024			Sep 30, 2024			Jun 30, 2024			Mar 31, 2024
Annualized FFO (A)			2,630			2,489			2,450			2,356			2,275			2,238			2,221			2,256
Net Debt (B)			18,568			18,346			18,030			17,615			16,963			16,679			16,308			16,016

Annualized FFO to Net Debt (A/B) 14.2 % 13.6 % 13.6 % 13.4 % 13.4 % 13.4 % 13.6 % 14.1 %

Earnings Coverage Ratio

Earnings coverage ratio is defined as earnings before income taxes, financing charges and equity income attributable to shareholders, 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)			Dec 31, 2025			Sep 30, 2025			Jun 30, 2025			Mar 31, 2025			Dec 31, 2024			Sep 30, 2024			Jun 30, 2024			Mar 31, 2024
Net income attributable to common shareholders			233			421			327			358			200			371			292			293
Income tax expense			30			60			61			68			17			56			57			51
Financing charges			175			172			169			163			158			158			157			148
Equity income			3			6			—			—			—			—			—			—
Earnings before income taxes, financing charges and equity income attributable to common shareholders			435			647			557			589			375			585			506			492

Twelve months ended (millions of dollars)

Dec 31, 2025

Dec 31, 2024

Earnings before income taxes, financing charges and equity income attributable to common shareholders (A)

2,228

1,958

Quarter ended (millions of dollars)			Dec 31, 2025			Sep 30, 2025			Jun 30, 2025			Mar 31, 2025			Dec 31, 2024			Sep 30, 2024			Jun 30, 2024			Mar 31, 2024
Financing charges			175			172			169			163			158			158			157			148
Capitalized interest			29			30			27			24			24			24			22			19
Financing charges and capitalized interest			204			202			196			187			182			182			179			167

Twelve months ended (millions of dollars)			Dec 31, 2025			Dec 31, 2024
Financing charges and capitalized interest (B)			789			710
Earnings coverage ratio = A/B			2.8			2.8

23

HYDRO ONE LIMITED

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2025 and 2024

RELATED PARTY TRANSACTIONS

The Province is a shareholder of Hydro One with approximately 47.1% ownership as at December 31, 2025. 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), and the OEB are related parties to Hydro One because they are controlled or significantly influenced by the Ministry. 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 years ended December 31, 2025 and 2024:

Year ended December 31 (millions of dollars)
Related Party			Transaction									2025			2024
Province			Dividends paid									370			350
Ministry			Broadband subsidy1									27			—
MOI			Broadband subsidy1									19			43
IESO			Power purchased									3,011			2,686
			Revenues for transmission services									2,388			2,252
			Amounts related to electricity rebates									1,110			1,170
			Distribution revenues related to rural rate protection									256			255
			Distribution revenues related to Wataynikaneyap Power LP									133			119
			Distribution revenues related to supply of electricity to remote northern communities									50			48
			Funding received related to Conservation and Demand Management programs									—			1
OPG			Power purchased									23			18
			Transmission revenues related to provision of services and supply of electricity									2			2
			Distribution revenues related to provision of services and supply of electricity									8			5
			Other revenues related to provision of services and supply of electricity									2			1
			Capital contribution received from OPG									20			3
			Costs related to the purchase of services									2			1
OEFC			Power purchased from power contracts administered by the OEFC									2			1
OEB			OEB fees									14			12

1 See section “Building Broadband Faster Act, 2021”, During 2025, Ministry replaced MOI in making broadband subsidy payments to Hydro One.

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 (ERM) program assists decision-makers throughout the organization with the management of key business risks, including new and emerging risks and opportunities.

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 are set out in the risk factors below. These risks, if they materialize, could have a materially adverse effect on the Company or its business, financial condition, or results of operations. This list is not a comprehensive list of all the risks to the Company, and the actual effect of any of the risks cited below could be materially different from what is described below. Additionally, other risks may arise or risks currently not considered material may become material in the future.

Risks Relating to Hydro One’s Business

Regulatory Risks and Risks Relating to Hydro One’s Revenues

Risks Relating to Actual Performance Against Forecasts

The Company’s ability to recover the actual costs of providing service and earn the allowed ROE depends on the Company achieving its forecasts established and approved in the rate-setting process. Actual costs could exceed the approved forecasts if, for example, the Company incurs operations, maintenance, administration, capital and financing costs above those included in the Company’s approved revenue requirement. The inability to recover any significant difference between forecast and actual expenses and to obtain associated regulatory approvals to recover the difference could materially adversely affect the Company’s financial condition and results of operations.

Further, the OEB approves the Company’s transmission and distribution rates based on projected electricity load and consumption levels, among other factors. If actual load or consumption materially falls below projected levels, the Company’s revenue, net income and cash flows for either, or both, of these businesses could be materially adversely affected.

The Company’s current revenue requirements for its transmission and distribution businesses are based on cost and other assumptions, including inflation, that may not materialize. There is no assurance that the OEB would allow rate increases sufficient to offset unfavourable financial impacts from unanticipated changes in electricity demand or in the Company’s costs.

24

HYDRO ONE LIMITED

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2025 and 2024

The Company is subject to risk of revenue loss from other factors, such as economic trends and conditions, changes in service territory, and weather conditions that influence the demand for electricity. The Company’s overall operating results may fluctuate substantially on a seasonal and year-to-year basis based on these trends and weather conditions. For instance, a cooler than normal summer or warmer than normal winter can be expected to reduce demand for electricity below that forecast by the Company, causing a decrease in the Company’s revenues, net income and cash flows as compared to the same period of the previous year.

The Company’s load could also be negatively affected by successful conservation and demand management programs whose results exceed forecasted expectations.

Risks Relating to Non-Rate Applications to the OEB

In addition to the matters described in the “Risks Relating to Obtaining Rate Orders” subsection below, the Company is also subject to the risk that it will not obtain, or will not obtain in a timely manner, required regulatory approvals for other matters, such as leave to construct applications, applications for mergers, acquisitions, amalgamations and divestitures, and environmental approvals. Appeals of OEB decisions and/or the need to obtain required occupation rights may result in significant delays, which could also lead to increased costs and project delays.

Decisions to acquire or divest other regulated businesses licensed by the OEB are subject to OEB approval. Accordingly, there is the risk that such matters may not be approved, or that unfavourable conditions will be imposed by the OEB.

Hydro One may face increased competition with other transmitters for opportunities to build new, large-scale transmission facilities in Ontario. The Company is subject to the risk that it will not be selected to build new transmission in Ontario, which could impair growth, disrupt operations and/or development, or have other adverse impacts.

Risks Relating to Rate-Setting Models for Transmission and Distribution

The OEB approves and periodically changes the rate-setting models and methodology for the transmission and distribution businesses. Changes to the application type, filing requirements, rate-setting model or methodology, or revenue requirement determination may have a material negative impact on Hydro One’s revenue and net income. For example, the OEB may in the future decide to reduce the allowed ROE for either of these businesses, modify the formula or methodology it uses to determine the ROE, or reduce the weighting of the equity component of the deemed capital structure. Any such reduction could reduce the net income of the Company. Similarly, the OEB may in the future consider other utility remuneration models, and any such change could affect Hydro One’s revenue and net income. If the OEB was to significantly change the formula for calculating ROE or the deemed regulatory capital structure, this could result in a material adverse impact to the financial condition of the Company.

The OEB’s Custom Incentive Rate-setting model requires that the term of a custom rate application be for multi-year periods. There are risks associated with forecasting key inputs such as revenues, operating expenses and capital over such a long period. For instance, if unanticipated capital expenditures arise that were not contemplated in the Company’s most recent rate decision, the Company may be required to incur costs that may not be recoverable until a future period or not recoverable at all in future rates. This could have a material adverse effect on the Company.

When rates are set for a multi-year period, including under a Custom Incentive Rate application, the OEB expects there to be no further rate applications for annual updates within the multi-year period, unless it is consistent with OEB approved funding mechanisms or there are exceptional circumstances, with the exception of the clearance of established deferral and variance accounts. For example, the OEB does not expect to address annual rate applications for updates for cost of capital (including ROE), working capital allowance or sales volumes. If there were an increase in interest rates over the period of a rate decision and no corresponding changes were permitted to the Company’s revenue requirement (including cost of capital parameters), then the result could be a decrease in the Company’s financial performance. See also “Market, Financial Instrument and Credit Risk”.

To the extent that the OEB approves an in-service variance account for the transmission and/or distribution businesses, and should the Company fail to meet the threshold levels of in-service capital, the OEB may reclaim a corresponding portion of the Company’s revenues.

Risks Relating to Capital Expenditures

In order to be recoverable in rates, capital expenditures require the approval of the OEB. There can be no assurance that all capital expenditures, including any imposed by or resulting from government or regulatory bodies, incurred by Hydro One will be approved by the OEB. For example, capital cost overruns including those due to economic trends and conditions including inflation; the potential imposition of duties, tariffs or trade restrictions; unexpected capital expenditures in maintaining or improving the Company’s assets; unexpected costs as a result of proposed legislation, including that relating to the expansion of broadband service in Canada; may not be recoverable in transmission or distribution rates. To the extent possible, Hydro One aims to mitigate this risk by ensuring expenditures are reasonable and prudent, and also by seeking from the regulator clear policy direction on cost responsibility, and by obtaining pre-approval of the need for capital expenditures.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2025 and 2024

Any regulatory decision by the OEB to disallow or limit the recovery of any capital expenditures would lead to a lower-than-expected approved revenue requirement or rate base, potential asset impairment or charges to the Company’s results of operations, any of which could have a material adverse effect on the Company.

Risks Relating to Obtaining Rate Orders

The Company is subject to the risk that the OEB will not approve the Company’s transmission and distribution revenue requirements requested in outstanding or future applications for rates. Rate applications for revenue requirements are subject to the OEB’s review process, usually involving participation from intervenors and a public hearing process. There can be no assurance that resulting decisions or rate orders issued by the OEB will permit Hydro One to recover all costs actually incurred, including the costs of debt and income taxes, or to earn a particular ROE. A failure to obtain acceptable rate orders, or approvals of appropriate returns on equity and the ability to recover in rates costs actually incurred, may materially adversely affect: Hydro One’s transmission and distribution businesses, the undertaking or timing of capital expenditures, ratings assigned by credit rating agencies, the cost and issuance of long-term debt, and other matters, any of which may in turn have a material adverse effect on the Company. In addition, there is no assurance that the Company will receive regulatory decisions in a timely manner and, therefore, the Company may incur costs before having an approved revenue requirement and cash flows could be impacted. The Company is also subject to the risk that the OEB could change the regulatory treatment of certain costs which may affect the Company’s accounting treatment of and ability to recover such costs.

Risk of Recoverability of Total Compensation Costs

Hydro One manages all of its total compensation costs, including pension and other post-employment and post-retirement benefits (OPEBs), subject to restrictions and requirements imposed by the collective bargaining process and legislative requirements. Any element of total compensation costs which is disallowed in whole or part by the OEB and therefore not recoverable from customers in rates could result in costs which could be material and could decrease net income, which could have a material adverse effect on the Company. The OEB Act prohibits Hydro One from recovering specified executive compensation costs in its rates.

The Company provides OPEBs to qualifying employees. Hydro One currently maintains the accrual accounting method with respect to OPEBs. If the OEB directed Hydro One to transition to a different accounting method for OPEBs or otherwise adjusted the basis of recovery for OPEB costs, this could result in income volatility, due to an inability of the Company to book the difference between the accrual and cash as a regulatory asset, and the Company might not be able to recover some costs. A determination that some of the Company’s post-employment and post-retirement benefit costs are not recoverable could have a material adverse effect on the Company.

Risks Relating to Government Action

The Province is, and is likely to remain, the largest shareholder in Hydro One Limited. The Province may be in a position of conflict from time to time as a result of being an investor in Hydro One Limited and also being a government actor setting broad policy objectives in the electricity industry. Government actions may not be in the interests of the Company or investors.

Governments may pass legislation or issue regulations at any time, including legislation or regulation impacting Hydro One, which could have potential material adverse effects on Hydro One and its business. Such government actions may include, but are not limited to, legislation, regulation, directives or shareholder action intended to reduce electricity rates, place constraints on compensation, or affect the governance of Hydro One. Such government actions could adversely affect the Company’s financial condition and results of operations, as well as public opinion and the Company’s reputation. Government action may also hinder Hydro One’s ability to pursue its strategy and/or objectives.

The Province has in the past passed legislation to place limits on executive compensation at Hydro One and there is no guarantee they may not do so in the future. Potential involvement by the Province in the Company’s executive compensation practices may inhibit the Company’s ability to attract and retain qualified executive talent, which may also impact the Company’s performance, strategy and/or objectives. The failure to attract and retain qualified executives could have a material adverse effect on the Company.

Government action may also impact the Company’s credit ratings as the Company’s credit ratings reflect, in part, the rating agencies’ assessment of government involvement in the business of Hydro One. The Company cannot predict what actions rating agencies may take in the future, positive or negative, including in response to government action or inaction relating to or impacting Hydro One. The failure to maintain the Company’s current credit ratings could adversely affect the Company’s financial condition and results of operations, and a downgrade in the Company’s credit ratings could restrict the Company’s ability to access debt capital markets and increase the Company’s cost of debt.

Indigenous Claims Risk

Some of the Company’s current and proposed transmission and distribution assets are or may be located on reserve (as defined in the Indian Act (Canada)) (Reserve) lands, or lands over which Indigenous people have Aboriginal, treaty, or other legal rights or claims. Some Indigenous leaders, communities, and their members have made assertions related to sovereignty and jurisdiction over Reserve lands and traditional territories (land traditionally occupied or used by a First Nation, Métis or Inuit

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2025 and 2024

group) and can assert their claims through the courts, tribunals, or direct action. These claims, and/or the settlement or resolution of these claims could have a material adverse effect on the Company or otherwise materially adversely impact the Company’s operations, including the development of current and future projects.

The Company’s operations and activities may give rise to the Crown having a duty to consult and potentially accommodate Indigenous communities. Procedural aspects of the Crown's duty to consult may be delegated to the Company by the Province or the federal government. A perceived failure by the Crown to sufficiently consult an Indigenous community, including communities with a traditional governance model not recognized under the Indian Act (Canada), or a perceived failure by the Company in relation to delegated consultation obligations, could result in legal challenges against the Crown and/or the Company, including judicial review or injunction proceedings, or could potentially result in direct action against the Company by a community or its citizens. If this occurs, it could disrupt or delay the Company’s operations and activities, including current and future projects, and have a material adverse effect on the Company.

Risk from Transfer of Assets Located on Reserves

The transfer orders by which the Company acquired certain of Ontario Hydro’s businesses as of April 1, 1999 did not transfer title to assets located on Reserves. The transfer of title to these assets did not occur because authorizations originally granted by the federal government for the construction and operation of these assets on Reserves could not be transferred without required consent. In several cases, the authorizations had either expired or had never been issued.

Currently, OEFC holds legal title to these assets and it is expected that the Company will manage them until it has obtained permits to complete the title transfer. To occupy Reserves, the Company must have valid permits as required by the Indian Act (Canada). For each permit, the Company may need to negotiate (an) agreement(s) with the First Nation, OEFC and any members of the First Nation who have occupancy rights. Any such agreement(s) include provisions whereby the First Nation consents to the issuance of a permit. For transmission assets, the Company must negotiate terms of payment. It is difficult to predict the aggregate amount that the Company may have to pay to obtain the required agreements from First Nations. If the Company cannot reach satisfactory agreements with the relevant First Nation to obtain federal permits, or is unable to obtain the actual federal permits for any other reason, it may have to relocate these assets to other locations and restore the lands at a cost that could be substantial. In a limited number of cases, it may be necessary to abandon a line and replace it with diesel generation facilities. In either case, the costs relating to these assets could have a material adverse effect on the Company if the costs are not recoverable in future rate orders.

Compliance with Laws and Regulations

Hydro One must comply with numerous laws and regulations affecting its business, including requirements relating to transmission and distribution companies, environmental laws, employment laws and health and safety laws. The failure of the Company to comply with these laws could have a material adverse effect on the Company’s business. See also “Environment Risk” and “Health and Safety Risk”.

For example, Hydro One’s licensed transmission and distribution businesses are required to comply with the terms of their licences, with codes and rules issued by the OEB, and with other regulatory requirements. In Ontario, the Market Rules issued by the IESO require the Company to, among other things, comply with applicable reliability standards established by the North American Electric Reliability Corporation (NERC) and Northeast Power Coordinating Council, Inc. (NPCC). The costs associated with compliance with these reliability standards are expected to be recovered through rates, but there can be no assurance that the OEB will approve the recovery of all of such costs. Failure to obtain such approvals could have a material adverse effect on the Company.

There is the risk that new legislation, regulations, requirements or policies will be introduced in the future or that regulatory bodies may change or modify the regulations or rules that apply to the Company. These may reduce Hydro One’s revenue, or may require Hydro One to incur additional costs, which may or may not be recovered in future transmission and distribution rates.

Risk of Natural and Other Unexpected Occurrences

The Company’s facilities are exposed to the effects of severe weather conditions, natural disasters, man-made events including, but not limited to, cyber and physical terrorist type attacks, events which originate from third-party connected systems, and any other potentially catastrophic events. The Company’s facilities may not withstand occurrences of these types in all circumstances.

The Company could also be subject to claims for damages from events which may be proximately connected with the Company’s assets (for example, wildfires), claims for damages caused by its failure to transmit or distribute electricity, costs related to ensuring its continued ability to transmit or distribute electricity or costs related to information or cyber security.

The Company does not have insurance for damage to its transmission and distribution wires, poles and towers located outside its transmission and distribution stations resulting from these or other events. Where insurance is available for the Company’s other assets and for damage claims and cyber security claims, such insurance coverage may have deductibles, limits and/or

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2025 and 2024

exclusions that may still expose the Company to material losses. Losses from lost revenues and repair costs could be substantial, especially for many of the Company’s facilities that are located in remote areas.

In the event that the Company is unable to recover such costs, this could have a material adverse effect on the Company.

Risk Associated with IT, Operational Technology (OT) Infrastructure, and Data Security

The Company’s ability to operate effectively in the Ontario electricity market is, in part, dependent upon it developing, modernizing, maintaining and managing complex IT and OT systems which are employed to operate and monitor its transmission and distribution facilities, financial and billing systems and other business systems. The Company’s increasing reliance on information systems and expanding data networks, as well as growing volume and complexity of data, increases its vulnerability, and exposure to information security threats. The Company’s transmission business is required to comply with various rules and standards for transmission reliability, including mandatory standards established by the NERC and the NPCC. These include standards relating to cyber-security and OT, which only apply to certain of the Company’s assets (generally being those whose failure could impact the functioning of the bulk electricity system). The Company may maintain different or lower levels of security for its assets that are not subject to these mandatory standards. The Company must also comply with various cyber-security and privacy-related regulatory requirements under the OEB’s Ontario Cyber Security Framework and legislative and licence requirements relating to the collection, use and disclosure of personal information and information regarding consumers, wholesalers, generators and retailers.

Cyber-attacks or unauthorized access to corporate IT and OT systems could result in service disruptions and system failures, which could have a material adverse effect on the Company, including as a result of a failure to provide electricity to customers. Because it operates critical infrastructure, Hydro One may be at greater risk of cyber-attacks from third parties (including state run or controlled parties) that could impair or incapacitate its assets. In addition, in the course of its operations, the Company collects, uses, processes and stores information which could be exposed in the event of a cyber-security incident or other unauthorized access or disclosure, such as information about customers, suppliers, counterparties, employees and other third parties.

Security and system disaster recovery controls are in place; however, there can be no assurance that there will not be system failures or security breaches or that such threats would be detected or mitigated on a timely basis. Upon occurrence and detection, the focus would shift from prevention to isolation, remediation and recovery until the incident has been fully addressed. Any such system failures or security breaches could have a material adverse effect on the Company.

Environment Risk

The Company is subject to extensive Canadian federal, provincial and municipal environmental regulation. Failure to comply could subject the Company to fines or other penalties. In addition, the presence or release of hazardous or other harmful substances could lead to claims by third parties or governmental orders requiring the Company to take specific actions such as investigating, controlling and remediating the effects of these substances. Although Hydro One is not a large emitter of greenhouse gases, the Company monitors its emissions to track and report on all sources, including sulphur hexafluoride or “SF6”. The Company could be subject to costs and other risks related to emissions. Contamination of the Company’s properties could limit its ability to sell or lease these assets in the future.

In addition, actual future environmental expenditures may vary materially from the estimates used in the calculation of the environmental liabilities provided for in the Company’s financial statements. The Company does not have insurance coverage for these environmental expenditures.

There is also risk associated with obtaining governmental approvals, permits, or renewals of existing approvals and permits related to constructing or operating facilities. This may require environmental assessment or result in the imposition of conditions, or both, which could result in delays and cost increases. Failure to obtain necessary approvals or permits could result in an inability to complete projects which may have a material adverse effect on the Company.

The Company’s facilities are exposed to the effects of severe weather conditions and natural disasters. The Company recognizes the risks associated with potential climate change and has developed plans to respond as appropriate. Climate change may have the effect of shifting weather patterns and increasing the severity and frequency of extreme weather events and natural disasters, which could impact Hydro One’s business. The Company’s facilities may not withstand occurrences of these types in all circumstances. Notwithstanding Hydro One’s efforts to adapt and increase grid resilience, the Company’s facilities are exposed to risks which may have an adverse effect on grid resilience. The Company could also be subject to claims for damages from events which may be proximately connected with the Company’s assets (for example, wildfires), claims for damages caused by its failure to transmit or distribute electricity or costs related to ensuring its continued ability to transmit or distribute electricity. The Company does not have insurance for damage to its transmission and distribution wires, poles and towers located outside its transmission and distribution stations resulting from these or other events. Where insurance is available for the Company’s other assets and for damage claims, such insurance coverage may have deductibles, limits and/or exclusions that may still expose the Company to material losses.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2025 and 2024

Losses from lost revenues and repair costs could be substantial, especially for many of the Company’s facilities that are located in remote areas.

In the event that the Company is unable to recover such costs, this could have a material adverse effect on the Company.

Labour Relations Risk

A substantial majority of the Company’s employees are unionized and are primarily represented by either the PWU or the Society. Over the past several years, significant effort has been expended to increase Hydro One’s flexibility to conduct operations in a more cost-efficient manner. Although the Company has achieved improved flexibility in its collective agreements, the Company may not be able to achieve further improvements, or at least not without increasing the risk of labour disruption. Hydro One Inc. reached a renewal collective agreement with the Society, covering the period from October 1, 2025 to March 31, 2028. Hydro One Inc. reached a renewal collective agreement with the PWU, covering the period from October 1, 2025 to March 31, 2028. Hydro One’s collective agreement with the CUSW covers the period from May 1, 2022 to April 30, 2026. Additionally, the EPSCA and a number of building trade unions have agreements, to which Hydro One is bound, covering the period from May 1, 2025 to April 30, 2030.

Future negotiations with unions present the risk of a labour disruption or dispute, risk to the Company’s ability to sustain the continued supply of electricity to customers, as well as potential risks to public safety and reputation. The Company also faces financial risks related to its ability to negotiate collective agreements consistent with its rate orders. Any of these could have a material adverse effect on the Company.

Risks Relating to Asset Condition, Capital Projects and Innovation

The Company continually incurs sustainment and development capital expenditures and monitors the condition of its assets to manage the risk of equipment failures and to determine the need for and timing of major refurbishments and replacements of its transmission and distribution infrastructure.

While traditionally a mature and stable industry, the electricity industry is facing rapid and dramatic technological change and increasing innovation, the consequences of which could have a material adverse effect on the Company, including a reduction in revenue.

Execution of the Company’s capital expenditure programs is partially dependent on external factors, such as OEB approvals; environmental approvals; municipal permits; equipment outage schedules that accommodate the IESO, generators and customers; other interrelated projects being on schedule; supply chain availability and/or cost and schedule variability for equipment suppliers, contracted services, and consulting services; and availability of contractor resources including in relation to workforce and equipment. Many of these external factors are beyond the Company’s control. There may also be a need for, among other things, Environmental Assessment Act (Ontario) approvals, approvals which require public meetings, appropriate engagement with Indigenous communities, OEB approvals of expropriation or early access to property, and other activities. Obtaining approvals and carrying out these processes may also be impacted by opposition to the proposed site of the capital investments. Delays in obtaining required approvals or failure to complete capital projects on a timely basis, or at all, could materially adversely affect transmission reliability or customers’ service quality or increase maintenance costs which could have a material adverse effect on the Company. Failure to receive approvals for projects when spending has already occurred would result in the inability of the Company to recover the investment in the project as well as forfeit the anticipated return on investment. The assets involved may be considered impaired and result in the write off of the value of the asset, negatively impacting net income. If the Company is unable to carry out capital expenditure plans in a timely manner, equipment performance may degrade, which may reduce network capacity, result in customer interruptions, compromise the reliability of the Company’s networks or increase the costs of operating and maintaining these assets. Any of these consequences could have a material adverse effect on the Company.

Increased competition for the development of large transmission projects and legislative changes relating to the selection of transmitters could impact the Company’s ability to expand its existing transmission system, which may have an adverse effect on the Company. The Company may not be selected to build new transmission as part of a competitive process. To the extent that other parties are selected to construct, own and operate new transmission assets, the Company’s share of Ontario’s transmission network would be reduced. Any delays in these new transmitters’ projects may impact the Company’s own projects that it is undertaking to in-service these new transmission assets.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2025 and 2024

Work Force Demographic Risk

By the end of 2025, approximately 9% of the Company’s employees who are members of the Company’s defined benefit and defined contribution pension plans were eligible for retirement, and by the end of 2026, approximately 11% could be eligible. These percentages are not evenly spread across the Company’s work force, but tend to be most significant in the most senior levels of the Company’s staff and among management staff. During 2025, approximately 4% of the Company’s work force (increased from 2% in 2024) elected to retire. Accordingly, the Company’s continued success will be tied to its ability to continue to attract and retain sufficient qualified staff to replace the capability lost through retirements and meet the demands of the Company’s work programs.

In addition, the Company expects the skilled labour market for its industry will remain highly competitive. Many of the Company’s current and potential employees are sought after as they possess skills and experience that are also highly coveted by other organizations inside and outside the electricity sector. The failure to attract, retain and deploy qualified personnel for Hydro One’s business could have a material adverse effect on the Company.

Risk Associated with Arranging Debt Financing

The Company expects to borrow to repay its existing indebtedness and to fund a portion of capital expenditures. Hydro One has substantial debt principal repayments coming due, including $925 million in 2026, $425 million in 2027 and $750 million in 2028. In addition, from time to time, the Company may draw on its syndicated bank credit facilities and/or issue short-term debt under Hydro One Inc.’s $2,300 million commercial paper program which would mature within one year of issuance. The Company also plans to incur continued material capital expenditures. Cash generated from operations, after the payment of expected dividends, will not be sufficient to fund the repayment of the Company’s existing indebtedness and capital expenditures. The Company’s ability to arrange sufficient and cost-effective debt financing could be materially adversely affected by numerous factors, including the regulatory environment in Ontario, the Company’s results of operations and financial position, market conditions, the ratings assigned to its debt securities by credit rating agencies, an inability of the Company to comply with its debt covenants, and general economic conditions (such as, among other things, changes in interest rates or international relations and geopolitical events that could cause weaker economic conditions or increase the volatility of the capital markets). A downgrade in the Company’s credit ratings could restrict the Company’s ability to access debt capital markets and increase the Company’s cost of debt. Any failure or inability on the Company’s part to borrow the required amounts of debt on satisfactory terms could impair its ability to repay maturing debt, fund capital expenditures and meet other obligations and requirements and, as a result, could have a material adverse effect on the Company. Increasing investor interest in ESG performance and reporting also has the potential to impact the cost and availability of the Company’s funding, as these factors may be increasingly connected to the quality of the Company’s ESG practices and related reporting, including reports addressing the allocation of funds and impact reporting under Hydro One’s Sustainable Financing Framework.

Market, Financial Instrument and Credit Risk

Market risk refers primarily to the risk of loss that results from changes in costs, foreign exchange rates and interest rates. The Company is exposed to fluctuations in interest rates as its regulated ROE is derived using a formulaic approach that takes into account anticipated interest rates. The Company issues debt from time to time to refinance maturing debt and for general corporate purposes. The Company is therefore exposed to fluctuations in interest rates in relation to such issuances of debt. Fluctuations in interest rates may also impact the funded position of Hydro One’s Defined Benefit Pension Plan, and associated pension asset or liability (see also “Pension Plan Risk”). The Company is not currently exposed to material foreign exchange risk.

The OEB-approved adjustment formula for calculating ROE in a deemed regulatory capital structure of 60% debt and 40% equity provides for increases and decreases depending on changes in benchmark interest rates for Government of Canada debt and the A-rated utility corporate bond yield spread. For the transmission and distribution businesses, during the Custom Incentive Rate period from 2023 to 2027, the OEB does not expect to address annual rate applications for updates to allowed ROE, so fluctuations will have no impact to net income. The Company has interest rate exposure in 2026 and beyond associated with the refinancing of maturing short- and long-term debt, as well as with debt issued for general corporate purposes and under the Sustainable Financing Framework which may include debt issued in relation to growth in rate base. The Company periodically uses interest rate swap agreements to mitigate elements of interest rate risk.

Financial assets create a risk that a counterparty will fail to discharge an obligation, causing a financial loss. Derivative financial instruments result in exposure to credit risk, since there is a risk of counterparty default. Hydro One monitors and minimizes credit risk through various techniques, including dealing with highly rated counterparties, limiting total exposure levels with individual counterparties, entering into agreements which enable net settlement, and monitoring the financial condition of counterparties. The Company does not trade in any energy derivatives. The Company is required to procure electricity on behalf of competitive electricity retailers and certain local distribution companies for resale to their customers. The resulting concentrations of credit risk are mitigated through the use of various security arrangements, including letters of credit, which are incorporated into the Company’s service agreements with these retailers in accordance with the OEB’s Retail Settlement Code.

The failure to properly manage these risks could have a material adverse effect on the Company.

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HYDRO ONE LIMITED

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2025 and 2024

Health and Safety Risk

Hydro One’s work environment can be inherently dangerous and there is a risk to health and safety of the public, our employees and contractors, as well as possible resultant operational and/or financial impacts. The Company is subject to federal and provincial legislation and regulations relating to health and safety. Findings of a failure to comply with these requirements could result in penalties and reputational risk, which could negatively impact the Company. Failure to comply could subject the Company to fines or other penalties. Any regulatory decision to disallow or limit the recovery of such costs could have a material adverse effect on the Company.

Pension Plan Risk

Hydro One has the Hydro One Defined Benefit Pension Plan in place for the majority of its employees. Contributions to the pension plan are established by actuarial valuations which are required to be filed with the Financial Services Regulatory Authority of Ontario on a triennial basis. The most recently filed valuation was prepared as at December 31, 2024, and was filed in September 2025, covering a three-year period from 2025 to 2027. The next required valuation will be prepared as at December 31, 2027 and is expected to be filed by no later than September 2028. Hydro One’s contributions to its pension plan satisfy, and are expected to continue to satisfy, minimum funding requirements. Contributions beyond 2027 will depend on the funded position of the plan, which is determined by investment returns, interest rates and changes in benefits and actuarial assumptions at that time. A determination by the OEB that some of the Company’s pension expenditures are not recoverable through rates could have a material adverse effect on the Company, and this risk may be exacerbated if the amount of required pension contributions increases.

Hydro One currently reports and recovers its pension costs on a cash basis, and maintains the accrual method with respect to OPEBs. Transitioning from the cash basis to an accrual method for pension costs may have material negative rate impacts for customers or material negative impacts on the Company should recovery of costs be disallowed by the OEB.

See also “Regulatory Risks and Risks Relating to Hydro One’s Revenues - Risk of Recoverability of Total Compensation Costs” for risks relating to recovery of pension costs.

Risk from Provincial Ownership of Transmission Corridors

The Province owns some of the corridor lands underlying the Company’s transmission system. Although the Company has the statutory right to use these transmission corridors, the Company may be limited in its options to expand or operate its systems. Also, other uses of the transmission corridors by third parties in conjunction with the operation of the Company’s systems, or adjacent land use by third parties, may increase safety or environmental risks, which could have a material adverse effect on the Company.

Litigation Risks

In the normal course of the Company’s operations, it becomes involved in, is named as a party to and is the subject of, various legal proceedings, including regulatory proceedings, tax proceedings and legal actions, relating to actual or alleged violations of law, common law damages claims, personal injuries, property damage, property taxes, land rights, the environment, contract disputes, claims by former employees and claims and proceedings by Indigenous groups. The outcome of outstanding, pending or future proceedings cannot be predicted with certainty and may be determined adversely to the Company, which could have a material adverse effect on the Company. Even if the Company prevails in any such legal proceeding, the proceedings could be costly and time-consuming and would divert the attention of management and key personnel from the Company’s business operations, which could adversely affect the Company.

Transmission Assets on Third-Party Lands Risk

Some of the lands on which the Company’s transmission assets are located are owned by third parties, including the Province and federal Crown, and are or may become subject to land claims by First Nations. The Company requires valid occupation rights to occupy such lands (which may take the form of land use permits, easements or otherwise). If the Company does not have valid occupational rights on third-party owned or controlled lands or has occupancy rights that are subject to expiry, it may incur material costs to obtain or renew such occupancy rights, or if such occupancy rights cannot be renewed or obtained it may incur material costs to remove and relocate its assets and restore the subject land. If the Company does not have valid occupancy rights and must incur costs as a result, this could have a material adverse effect on the Company or otherwise materially adversely impact the Company’s operations.

Reputational, Public Opinion and Political Risk

Reputation risk is the risk of negative publicity or the public’s negative perceptions towards Hydro One and the electricity industry that may result in a detrimental impact to Hydro One’s business, operations or financial condition leading to a deterioration of Hydro One’s reputation. Hydro One’s reputation and/or brand could be negatively impacted by changes in public opinion, attitudes towards the Company’s privatization, failure to deliver on its customer and/or stakeholder promises, failure to comply with mandatory reliability regulations established by the NERC and NPCC, failure to adequately respond to social issues raised by employees, partners and/stakeholders and other external forces. Adverse reputational events or political actions could have a material adverse effect on Hydro One’s business and prospects including, but not limited to, delays or denials of requisite

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2025 and 2024

approvals, such as denial of requested rates, and accommodations for Hydro One’s planned projects, escalated costs, legal or regulatory action, and damage to stakeholder and community relationships. Any of these could have a material adverse impact on Hydro One and its business, financial condition and results of operations.

Risks Associated with Acquisitions

Acquisitions include inherent risks that some or all of the expected benefits may fail to materialize, or may not occur within the time periods anticipated, and Hydro One may incur material unexpected costs or liabilities. Realization of the anticipated benefits would depend, in part, on the Company’s ability to successfully integrate the acquired business, including the requirement to devote management attention and resources to integrating business practices and support functions. The failure to realize the anticipated benefits, the diversion of management’s attention, or any delays or difficulties encountered in connection with the integration could have an adverse effect on the Company’s business, results of operations, financial condition or cash flows.

Infectious Disease Risk

An outbreak of infectious disease, in the form of an epidemic, a pandemic, or a similar public health threat, could materially adversely impact the Company. The extent of any such adverse impact on the Company is uncertain, and may depend on the length and severity of any such infectious disease outbreak, any resultant government regulations, guidelines and actions, and any related adverse changes in general economic and market conditions. Such circumstances could impact, in particular: the Company’s operations and workforce, including security of supply, both with respect to availability and affordability, which individually or collectively may impact the Company's ability to complete operating and capital work programs as planned, including within scope and budget; certain financial obligations of the Company, including pension contributions and other post-retirement benefits, as a result of changes in prevailing market conditions; the Company’s expected revenues; reductions in overall electricity consumption and load, both short term and long term; overdue accounts and bad debt increases as a result of changes in the ability of the Company’s customers to pay; liquidity and the Company’s ability to raise capital; the Company’s ability to pay or increase dividends; the timing of increased rates; the Company’s ability to recover incremental costs and lost revenues linked to the outbreak; the Company’s ability to file regulatory filings on a timely basis; timing of regulatory decisions and the impacts those decisions may have on the Company or its ability to implement them; and customer and stakeholder needs and expectations.

The Company also faces risks and costs associated with implementation of business continuity plans and modified work conditions, including the risks and costs associated with maintaining or reducing its workforce, making the required resources available to its workforce to enable essential work, including remotely where possible, and to keep its workforce healthy, as well as risks and costs associated with recovery of normal operations. Furthermore, the Company is dependent on third party providers for certain activities, and relies on a strong international supply chain. Any significant disruption to those providers or the supply chain resulting from an outbreak of infectious disease could materially adversely impact the Company.

Risks Relating to the Common Shares of Hydro One Limited

Hydro One’s common shares trade on the TSX. The trading price of the common shares has in the past been, and may in the future be, subject to significant fluctuations. These fluctuations may be caused by events or factors related or unrelated to Hydro One’s operating performance and/or beyond its control, including: the risk factors described herein; general economic conditions within Ontario and Canada and globally, including changes in interest rates; inflation; the potential imposition of duties, tariffs or trade restrictions; changes in electricity prices; changes in electricity demand; weather conditions; actual or anticipated fluctuations in Hydro One’s quarterly and annual results and the results of public companies similar to Hydro One; Hydro One’s businesses, operations, results and prospects; Hydro One’s reputation and its relationship with the Province; the timing and amount of dividends, if any, declared on the common shares; future issuances of common shares or other securities by Hydro One or Hydro One Inc.; Hydro One’s relationship with its regulator; changes in government regulation, taxes, legal proceedings or other developments; shortfalls in Hydro One’s operating results from levels forecasted by securities analysts; investor sentiment toward energy companies in general or companies adopting ESG performance and reporting practices and the achievement by companies of ESG targets; maintenance of acceptable credit ratings or credit quality; and the general state of the securities markets. These and other factors may impair the development or sustainability of a liquid market for the common shares and the ability of investors to sell common shares at an attractive price.

32

HYDRO ONE LIMITED

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2025 and 2024

Risks Relating to the Company’s Relationship with the Province

Ownership and Continued Influence by the Province and Voting Power; Share Ownership Restrictions

The Province currently owns approximately 47.1% of the outstanding common shares of Hydro One. The Electricity Act restricts the Province from selling voting securities of Hydro One (including common shares) of any class or series if it would own less than 40% of the outstanding number of voting securities of that class or series after the sale and in certain circumstances also requires the Province to take steps to maintain that level of ownership. Accordingly, the Province is expected to continue to maintain a significant ownership interest in voting securities of Hydro One for an indefinite period.

As a result of its significant ownership of the common shares of Hydro One, the Province has, and is expected indefinitely to have, the ability to determine or significantly influence the outcome of shareholder votes, subject to the restrictions in the Governance Agreement between Hydro One and the Province dated November 5, 2015 (Governance Agreement) (available on SEDAR+ at www.sedarplus.com). Despite the terms of the Governance Agreement in which the Province has agreed to engage in the business and affairs of the Company as an investor and not as a manager, there is a risk that the Province’s engagement in the business and affairs of the Company as an investor will be informed by its policy objectives and may influence the conduct of the business and affairs of the Company in ways that may not be aligned with the interests of other investors. Notwithstanding the Governance Agreement, and in light of actions historically taken by the Province, there can be no assurance that the Province will not take other actions in the future that could be detrimental to the interests of investors in Hydro One. See “Risks Relating to Government Action” above.

The share ownership restrictions in the Electricity Act (Share Ownership Restrictions) and the Province’s significant ownership of common shares of Hydro One together effectively prohibit one or more persons acting together from acquiring control of Hydro One. They also may limit or discourage transactions involving other fundamental changes to Hydro One and the ability of other shareholders to successfully contest the election of the directors proposed for election pursuant to the Governance Agreement. The Share Ownership Restrictions may also discourage trading in, and may limit the market for, the common shares and other voting securities.

Nomination of Directors and Confirmation of Chief Executive Officer (CEO) and Chair

Although director nominees (other than the CEO) are required to be independent of both the Company and the Province pursuant to the Governance Agreement, there is a risk that the Province will nominate or confirm individuals who satisfy the independence requirements but who it considers are disposed to support and advance its policy objectives and give disproportionate weight to the Province’s interests in exercising their business judgment and balancing the interests of the stakeholders of Hydro One. This, combined with the fact certain matters require a two-thirds vote of the Board, could allow the Province to unduly influence certain Board actions such as confirmation of the Chair and confirmation of the CEO.

Board Removal Rights

Under the Governance Agreement, the Province has the right to withhold from voting in favour of all director nominees and has the right to seek to remove and replace the entire Board, including in each case its own director nominees but excluding the CEO and, at the Province’s discretion, the Chair. In exercising these rights in any particular circumstance, the Province is entitled to vote in its sole interest, which may not be aligned with the interests of other stakeholders of Hydro One.

More Extensive Regulation

Although under the Governance Agreement, the Province has agreed to engage in the business and affairs of Hydro One as an investor and not as a manager and has stated that its intention is to achieve its policy objectives through legislation and regulation as it would with respect to any other utility operating in Ontario, there is a risk that the Province will exercise its legislative and regulatory power to achieve policy objectives in a manner that has a material adverse effect on the Company. See “Risks Relating to Government Action” above.

Prohibitions on Selling the Company’s Transmission or Distribution Business

The Electricity Act prohibits the Company from selling all or substantially all of the business, property or assets related to its transmission system or distribution system that is regulated by the OEB. There is a risk that these prohibitions may limit the ability of the Company to engage in sale transactions involving a substantial portion of either system, even where such a transaction may otherwise be considered to provide substantial benefits to the Company and the holders of the common shares.

Future Sales of Common Shares by the Province

Although the Province has indicated that it does not intend to sell further common shares of Hydro One, the registration rights agreement between Hydro One and the Province dated November 5, 2015 (available on SEDAR+ at www.sedarplus.com) grants the Province the right to request that Hydro One file one or more prospectuses and take other procedural steps to facilitate secondary offerings by the Province of the common shares of Hydro One. Future sales of common shares of Hydro One by the Province, or the perception that such sales could occur, may materially adversely affect market prices for these common shares and impede Hydro One’s ability to raise capital through the issuance of additional common shares, including the number of common shares that Hydro One may be able to sell at a particular time or the total proceeds that may be realized.

33

HYDRO ONE LIMITED

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2025 and 2024

Limitations on Enforcing the Governance Agreement

The Governance Agreement includes commitments by the Province restricting the exercise of its rights as a holder of voting securities, including with respect to the maximum number of directors that the Province may nominate and on how the Province will vote with respect to other director nominees. Hydro One’s ability to obtain an effective remedy against the Province, if the Province were not to comply with these commitments, is limited as a result of the Proceedings Against the Crown Act (Ontario). This legislation provides that the remedies of injunction and specific performance are not available against the Province, although a court may make an order declaratory of the rights of the parties, which may influence the Province’s actions. A remedy of damages would be available to Hydro One, but damages may not be an effective remedy, depending on the nature of the Province’s non-compliance with the Governance Agreement.

CRITICAL ACCOUNTING ESTIMATES AND JUDGMENTS

The preparation of Hydro One Consolidated Financial Statements requires the Company to make key estimates and critical judgments that affect the reported amounts of assets, liabilities, revenues and costs, and related disclosures of contingencies. Hydro One bases its estimates and judgments on historical experience, current conditions and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities, as well as identifying and assessing the Company’s accounting treatment with respect to commitments and contingencies. Actual results may differ from these estimates and judgments. Hydro One has identified the following critical accounting estimates and judgments used in the preparation of its Consolidated Financial Statements:

Revenues

Distribution revenues attributable to the delivery of electricity are based on OEB-approved distribution rates and are recognized on an accrual basis and include billed and unbilled revenues. Billed revenues are based on the amount of electricity delivered as measured from customer meters. At the end of each month, the amount of electricity delivered to customers since the date of the last billed meter reading is estimated, and the corresponding unbilled revenue is recorded. The unbilled revenue estimate is affected by energy consumption and changes in the composition of customer classes.

Regulatory Assets and Liabilities

Hydro One’s regulatory assets represent certain amounts receivable from electricity customers in a future period and costs that have been deferred for accounting purposes because it is probable that they will be recovered in future rates. In addition, the Company has recorded regulatory liabilities that generally represent amounts that are refundable to electricity customers in future rates. The regulatory assets mainly include amounts related to the deferred income taxes, post-retirement and post-employment non-service costs, costs related to designated broadband projects, environmental liabilities and share-based compensation costs. The Company’s regulatory liabilities pertain primarily to deferral and variance accounts, and include amounts related to the pension benefit liability. The regulatory assets and liabilities can be recognized for rate-setting and financial reporting purposes only if the amounts have been approved for inclusion in the electricity rates by the OEB, or if such approval is judged to be probable by management. The Company continually assesses the likelihood of recovery of each of its regulatory assets and continues to believe that it is probable that the OEB will include its regulatory assets and regulatory liabilities in setting future rates. If, at some future date, the Company judges that it is no longer probable that the OEB will include a regulatory asset or regulatory liability in setting future rates, the respective carrying amount would be reflected in results of operations, prospectively from the date the Company’s assessment is made.

Employee Future Benefits

Hydro One’s employee future benefits consist of pension and post-retirement and post-employment plans, and include pension, group life insurance, health care, and long-term disability benefits provided to the Company’s current and retired employees. Employee future benefits costs are included in Hydro One’s labour costs that are either charged to results of operations or capitalized as part of the cost of property, plant and equipment and intangible assets. Changes in assumptions affect the benefit obligation of the employee future benefits and the amounts that will be charged to results of operations or capitalized in future years. The following significant assumptions and estimates are used to determine employee future benefit costs and obligations:

Weighted Average Discount Rate

The weighted average discount rate used to calculate the employee future benefits obligation is determined at each year end by referring to the most recently available market interest rates based on “AA”-rated corporate bond yields reflecting the duration of the applicable employee future benefit plan. The discount rate as at December 31, 2025 increased to 5.02% (2024 - 4.73%) for pension benefits and increased to 5.05% (2024 - 4.75%) for the post-retirement and post-employment plans. The increase in the discount rate has resulted in a corresponding decrease in employee future benefits liabilities for the pension, post-retirement and post-employment plans for accounting purposes. The liabilities are determined by independent actuaries using the projected benefit method prorated on service and based on assumptions that reflect management’s best estimates.

34

HYDRO ONE LIMITED

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2025 and 2024

Expected Rate of Return on Plan Assets

The expected long-term rate of return on pension plan assets is 7.20% for the year ended December 31, 2025 (2024 - 7.00%). This rate is based on the long-term return expectations at the beginning of 2025 and reflects the pension plan target asset mix set out in the Statement of Investment Policies and Procedures dated August 13, 2024.

Rates of return on the respective portfolios are determined with reference to respective published market indices. The expected rate of return on pension plan assets reflects the Company’s long-term expectations. The Company believes that this assumption is reasonable because, with the pension plan’s balanced investment approach, the higher volatility of equity investment returns is intended to be offset by the greater stability of fixed-income and short-term investment returns. The net result, on a long-term basis, is a lower return than might be expected by investing in equities alone. In the short term, the pension plan can experience fluctuations in actual rates of return.

Rate of Cost of Living Increase

The rate of cost of living increase is determined by considering differences between long-term Government of Canada nominal bonds and real return bonds, which increased from 1.81% per annum as at December 31, 2024 to approximately 1.89% per annum as at December 31, 2025. Based on the Bank of Canada’s commitment to keep long-term inflation between 1.00% and 3.00%, in addition to current and anticipated trends, management believes that a long-term assumption of 2.00% per annum is reasonable for employee future benefits liability valuation purposes as at December 31, 2025 (2024 - 2.00%).

Salary Increase Assumptions

Salary increases should reflect general wage increases plus an allowance for merit and promotional increases for current members of the Plan and should be consistent with the assumptions for consumer price inflation and real wage growth in the economy. The merit and promotion scale was developed based on the salary increase assumption review performed in 2025. The review considered actual salary experience from 2019 to 2024 using valuation data for all active employees with defined benefit pension entitlements (split by age and service) and Hydro One’s expectation of future salary increases. Additionally, the salary scale reflects negotiated salary increases over the contract period.

Mortality Assumptions

The Company’s employee future benefits liability is also impacted by changes in life expectancies used in mortality assumptions. Increases in life expectancies of plan members result in increases in the employee future benefits liability. For the pension and post-retirement plans, the mortality assumption used as at December 31, 2025 is 90% of the 2014 Canadian Pensioners Mortality Private Sector table, projected generationally using an updated mortality improvement scale from the Mortality Improvements Research report, that was published by the Canadian Institute of Actuaries in April 2024 (scale “MI-2024”). The assumption at December 31, 2024 used mortality improvement Scale CPM-B. The multiplier applied to the assumed mortality table is based on the result of a mortality experience study that was conducted in 2021. For the post-employment plan, the mortality assumption used as at December 31, 2025 is the disability mortality table from the 2009 to 2015 Canadian Institute of Actuaries Group Long Term Disability Termination Study, which is the most recent publicly available table that reflects Canadian experience and is commonly used by Canadian plan sponsors.

Rate of Increase in Health Care Cost Trends

The costs of post-retirement and post-employment benefits are determined at the beginning of the year and are based on assumptions for expected claims experience and future health care cost inflation. For the post-retirement benefit plans, a study of Hydro One’s historical per capita health care cost trend experience was conducted in 2017. The health and dental trends reflect the results of this study as well as macroeconomic inputs such as the expected long-term rates of general inflation and real GDP growth. The environment of high general inflation that was present in Canada in 2022 and 2023 resulted in short-term upward pressure on the cost of certain medical services covered by Hydro One's post-retirement and post-employment benefit plans. However, these effects were muted somewhat by plan design and government regulation. These effects in 2023 as well as any residual effects that have occurred in 2024 and 2025 have been captured though the use of actual claims experience from 2023, 2024 and year-to-date 2025 (through November 30) in the development of the per capita claims cost assumptions being used for the December 31, 2025 disclosures. Based on the above, Hydro One is not making any changes to its health care trend rate assumptions for the December 31, 2025 disclosures from what was used at December 31, 2024.

35

HYDRO ONE LIMITED

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2025 and 2024

DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROL OVER FINANCIAL REPORTING

Disclosure controls and procedures are the processes designed to ensure that information is recorded, processed, summarized and reported on a timely basis to the Company’s management, including its CEO and Chief Financial and Regulatory Officer (CFRO), as appropriate, to make timely decisions regarding required disclosure in the MD&A and consolidated financial statements. At the direction of the Company’s CEO and CFRO, management evaluated disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, management concluded that the Company’s disclosure controls and procedures were effective as at December 31, 2025.

Internal control over financial reporting is designed by, or under the direction of the CEO and CFRO to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with U.S. GAAP. The Company’s internal control over financial reporting framework includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and disposition of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of consolidated financial statements in accordance with U.S. GAAP, and that receipts and expenditures of the Company are being made only in accordance with authorization of management and directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the Company’s consolidated financial statements.

The Company’s management, at the direction of the CEO and CFRO, evaluated the effectiveness of the design and operation of internal control over financial reporting based on the criteria established in the Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on that evaluation, management concluded that the Company’s internal control over financial reporting was effective as at December 31, 2025.

Internal controls, 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. Furthermore, the effectiveness of internal control is affected by change and subject to the risk that internal control effectiveness may change over time.

There were no changes in the design of the Company’s internal control over financial reporting during the three months ended December 31, 2025 that have materially affected, or are reasonably likely to materially affect, the operation of the Company’s internal control over financial reporting.

Management will continue to monitor its systems of internal control over reporting and disclosure and may make modifications from time to time as considered necessary.

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

Guidance

Date issued

Description

ASU Effective Date

Impact on Hydro One

ASU 2024-02

March 2024

The amendments contain modifications to the codification that remove various concept statements which may be extraneous and not required to understand or apply the guidance or references used in prior statements to provide guidance in certain topical areas.

Fiscal years beginning after December 15, 2024.

No impact upon adoption

ASU 2023-09

December 2023

The amendments address investor requests for more transparency about income tax information through improvements to income tax disclosures primarily related to the rate reconciliation and income taxes paid information.

Annual periods beginning after December 15, 2024.

Adoption of the standard does not materially affect Hydro One’s income tax disclosures.

36

HYDRO ONE LIMITED

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2025 and 2024

Recently Issued Accounting Guidance Not Yet Adopted

Guidance

Date issued

Description

ASU Effective Date

Impact on Hydro One

ASU 2023-06

October 2023

The 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 2024

The 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 2025-03

May 2025

The 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 2025-05

July 2025

The 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

ASU 2025-06

September 2025

The 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 periods beginning after December 15, 2027.

Under assessment

ASU 2025-09

November 2025

The 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 2025-10

December 2025

The 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 2025-11

December 2025

The 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 2025-12

December 2025

The 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

37

HYDRO ONE LIMITED

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2025 and 2024

SUMMARY OF FOURTH QUARTER RESULTS OF OPERATIONS

Three months ended December 31 (millions of dollars, except EPS)															2025			2024			Change
Revenues
Transmission															491			505			(2.8		%)
Distribution															1,757			1,583			11.0		%
Other															20			7			185.7		%
															2,268			2,095			8.3		%
Costs
Purchased power															1,287			1,060			21.4		%
OM&A
Transmission															80			128			(37.5		%)
Distribution															153			204			(25.0		%)
Other															25			41			(39.0		%)
															258			373			(30.8		%)
Depreciation, amortization and asset removal costs															287			286			0.3		%
															1,832			1,719			6.6		%
Income before financing charges, equity income and income tax expense															436			376			16.0		%
Financing charges															175			158			10.8		%
Equity income															3			—			—		%
Income before income tax expense															264			218			21.1		%
Income tax expense															30			17			76.5		%
Net income															234			201			16.4		%
Net income attributable to common shareholders of Hydro One															233			200			16.5		%
Basic EPS															$0.39			$0.33			18.2		%
Diluted EPS															$0.39			$0.33			18.2		%
Assets Placed In-Service
Transmission															953			754			26.4		%
Distribution															351			342			2.6		%
Other															6			4			50.0		%
															1,310			1,100			19.1		%
Capital Investments
Transmission															629			476			32.1		%
Distribution															303			313			(3.2		%)
Other															7			10			(30.0		%)
															939			799			17.5		%

38

HYDRO ONE LIMITED

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2025 and 2024

Net Income

Net income attributable to common shareholders for the quarter ended December 31, 2025 of $233 million is $33 million, or 16.5%, higher than the same period in the prior year, primarily due to:

•lower OM&A costs primarily resulting from lower corporate support costs; partially offset by

•lower revenues, net of purchased power,8 resulting from regulatory adjustments, primarily due to higher earnings sharing in the current period, partially offset by higher revenues resulting from higher average monthly peak demand and energy consumption, as well as increased transmission and distribution revenues due to OEB-approved 2025 rates;

•higher financing charges attributable to an increase in outstanding long-term debt, partially offset by higher capitalized interest; and

•higher income tax expense primarily resulting from higher pre-tax earnings.

EPS

Basic EPS was $0.39 in the fourth quarter of 2025, compared to Basic EPS of $0.33 in the fourth quarter of 2024.

Revenues

The year-over-year decrease of $14 million, or 2.8%, in transmission revenues during the quarter primarily resulted from:

•regulatory adjustments, including a higher earnings sharing accrual in the current period; partially offset by

•higher average monthly peak demand; and

•higher revenues resulting from OEB-approved 2025 rates.

The year-over-year increase of $174 million, or 11.0%, in distribution revenues during the quarter primarily resulted from:

•higher purchased power costs, which are fully recovered from ratepayers and thus net income neutral;

•higher revenues resulting from OEB-approved 2025 rates; and

•higher energy consumption; partially offset by

•regulatory adjustments, mainly attributable to a higher earnings sharing accrual in the current period; and

•lower revenue associated with mutual storm assistance costs recovered from third parties in the prior year, which is offset in OM&A and therefore net income neutral.

Distribution revenues, net of purchased power,8 decreased by 10.1% during the fourth quarter of 2025 compared to the prior year primarily due to:

•regulatory adjustments, including a higher earnings sharing accrual in the current period; and

•lower revenue associated with mutual storm assistance costs recovered from third parties, which is offset in OM&A and therefore net income neutral; partially offset by

•higher revenues resulting from OEB-approved 2025 rates; and

•higher energy consumption.

OM&A Costs

The year-over-year decrease of $48 million, or 37.5%, in transmission OM&A costs during the quarter was primarily due to:

•severance costs in the prior year;

•lower corporate support costs; and

•lower work program expenditures, including work related to facilities maintenance and vegetation management.

The year-over-year decrease of $51 million, or 25.0%, in distribution OM&A costs during the quarter was primarily due to:

•severance costs in the prior year;

•net income neutral items, including mutual storm assistance costs and lower fuel costs of Hydro One Remotes, both of which are offset in revenue; and

•lower corporate support costs; partially offset by

•higher work program expenditures, including emergency restoration and vegetation management.

The year-over-year decrease of $16 million, or 39.0%, in other OM&A costs during the quarter was due to various factors, including lower costs in Acronym primarily due to higher third party service costs in the prior year.

Depreciation, Amortization and Asset Removal Costs

Depreciation, amortization and asset removal costs for the fourth quarter of 2025 were comparable to the same period in 2024.

8 See section “Non-GAAP Financial Measures”.

39

HYDRO ONE LIMITED

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2025 and 2024

Financing Charges

The $17 million, or 10.8%, increase in financing charges for the quarter ended December 31, 2025, was primarily due to an increase in outstanding long-term debt, partially offset by higher capitalized interest.

Income Tax Expense

Income tax expense for the fourth quarter of 2025 increased by $13 million compared to the same period in 2024. This resulted in a realized ETR of approximately 11.4% in the fourth quarter of 2025, compared to approximately 7.8% in the fourth quarter of the prior year.

The increase in ETR for the three months ended December 31, 2025 was primarily attributable to:

•higher pre-tax earnings; and

•lower deductible timing differences compared to the prior year.

Assets Placed In-Service

The increase in transmission assets placed in-service during the fourth quarter was primarily due to:

•timing of assets placed in-service for station refurbishments and replacements, including the Bruce A Transmission station, the Merivale Transmission Station, and the Lauzon Transmission Station; and

•investments placed in-service for customer connection projects; partially offset by

•investments placed in-service for the Chatham to Lakeshore Transmission Line; and

•lower volume of line refurbishments and wood pole replacements.

The increase in distribution assets placed in-service during the fourth quarter was primarily due to:

•investments placed in-service for Ontario’s broadband initiative;

•assets placed in-service for the AMI 2.0 system; and

•higher volume of assets placed in-service for customer connections; partially offset by

•lower volume of wood pole replacements and line refurbishments;

•timing of assets placed in-service for system capability reinforcement projects; and

•assets placed in-service for the Orleans Operation Centre in the prior year.

Capital Investments

The increase in transmission capital investments during the fourth quarter was primarily due to:

•higher investments in the Waasigan Transmission Line Project;

•investments in the St. Clair Transmission Line Project;

•higher spend on major development projects; and

•higher spend on customer connections; partially offset by

•lower volume of line refurbishments and wood pole replacements.

The decrease in distribution capital investments during the fourth quarter was primarily due to:

•lower volume of wood pole replacements;

•investments in the Orillia Distribution Warehouse, Orillia Operation Centre, and Orleans Operation Centre; and

•lower volume of PCB transformer replacements; partially offset by

•investments in Ontario’s broadband initiative; and

•investments in the AMI 2.0 system.

40

HYDRO ONE LIMITED

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2025 and 2024

HOHL - CONSOLIDATING SUMMARY FINANCIAL INFORMATION

Hydro One Limited fully and unconditionally guarantees the payment obligations of its wholly-owned subsidiary, HOHL, issuable under the short form base shelf prospectus dated November 29, 2024. Accordingly, the following consolidating summary financial information is provided in compliance with the requirements of section 13.4 of National Instrument 51-102 - Continuous Disclosure Obligations providing for an exemption for certain credit support issuers. The tables below contain consolidating summary financial information as at and for the years ended December 31, 2025 and December 31, 2024 for: (i) Hydro One Limited; (ii) HOHL; (iii) the subsidiaries of Hydro One Limited, other than HOHL, on a combined basis; (iv) consolidating adjustments; and (v) Hydro One Limited and all of its subsidiaries on a consolidated basis, in each case for the periods indicated. Such summary financial information is intended to provide investors with meaningful and comparable financial information about Hydro One Limited and its subsidiaries. This summary financial information should be read in conjunction with Hydro One Limited's most recently issued annual and interim financial statements. This summary financial information has been prepared in accordance with U.S. GAAP, as issued by the FASB.

Year ended December 31 (millions of dollars)			Hydro One Limited						HOHL						Subsidiaries of Hydro One Limited, other than HOHL						Consolidating Adjustments						Total Consolidated Amounts of Hydro One Limited
			2025			2024			2025			2024			2025			2024			2025			2024			2025			2024
Revenue			794			757			—			—			10,115			9,462			(1,868)			(1,735)			9,041			8,484
Net Income (Loss) Attributable to Common Shareholders			825			777			—			—			2,248			1,978			(1,734)			(1,599)			1,339			1,156

As at December 31 (millions of dollars)			Hydro One Limited						HOHL						Subsidiaries of Hydro One Limited, other than HOHL						Consolidating Adjustments						Total Consolidated Amounts of Hydro One Limited
			2025			2024			2025			2024			2025			2024			2025			2024			2025			2024
Current Assets			940			953			—			—			4,172			4,229			(2,938)			(3,065)			2,174			2,117
Non-Current Assets			3,295			3,226			—			—			59,529			54,743			(25,327)			(23,404)			37,497			34,565
Current Liabilities			1,075			1,061			—			—			5,420			5,468			(2,905)			(3,028)			3,590			3,501
Non-Current Liabilities			425			425			—			—			40,475			36,291			(17,565)			(15,708)			23,335			21,008

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; the Company’s maturing debt; expectations and impact of the Company’s credit ratings; the Company’s ongoing and planned projects, initiatives and expected capital investments, including expected approvals, results, costs, funding sources and in-service and completion dates; expectations regarding the Company’s Z-Factor application and impacts of its outcome; contractual obligations and other commercial commitments; the BBFA, as well as related regulations, and expected impacts; expectations regarding the Ministry’s subsidies program to ISPs and its results and expected timeline; the Company’s assessment of recovery and impacts related to the OEB-established generic variance and deferral accounts; expected impacts and results of the OEB’s new cost of capital parameters; 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 first integrated energy plan and the target in-service dates; collective agreements and bargaining; Protect Ontario by Unleashing our Economy Act and expected impacts; the Company’s expectations regarding participation in the TSF Registry and expected engagement with IESO and industry and the government decision on potential competitive procurement projects; dividends; non-GAAP financial measures; internal controls over financial reporting and disclosure; the MTN Program, including the expected filing of a new MTN Program prospectus; 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,

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HYDRO ONE LIMITED

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2025 and 2024

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.

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 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;

42

HYDRO ONE LIMITED

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2025 and 2024

•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;

•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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FAQ

How did Hydro One Limited (HRNNF) perform financially in 2025?

Hydro One’s 2025 financial performance strengthened, with net income rising to $1,349 million from $1,165 million. Revenue increased to $9,041 million, up from $8,484 million, supported by higher distribution and transmission revenues while operating costs grew more slowly than sales.

What were Hydro One Limited (HRNNF) 2025 earnings per share and dividends?

In 2025, Hydro One reported basic and diluted EPS of $2.23, compared with $1.93 and $1.92 in 2024. Dividends declared per common share were $1.31, up from $1.24, indicating continued dividend growth supported by higher earnings and strong operating cash flow.

How strong was Hydro One Limited (HRNNF) cash flow in 2025?

Hydro One generated $2,695 million of net cash from operating activities in 2025, up from $2,534 million. This cash flow funded $788 million of common dividends and significant capital expenditures and equity investments, despite total net cash used in investing activities of $3,514 million.

What does the 2025 balance sheet show for Hydro One Limited (HRNNF)?

At December 31, 2025, Hydro One reported $39,671 million of total assets and $26,925 million of total liabilities. Long-term debt (excluding current portion) was $18,092 million, while total equity increased to $12,727 million from $12,154 million, reflecting retained earnings growth.

How important are regulatory assets and liabilities for Hydro One Limited (HRNNF)?

Regulation is significant: Hydro One reported $3,867 million of regulatory assets and $1,851 million of regulatory liabilities at year-end 2025. These balances arise from Ontario Energy Board decisions and timing differences in recovering or refunding specific costs through future electricity rates.

What opinion did auditors give on Hydro One Limited (HRNNF) 2025 statements?

KPMG LLP issued an unqualified opinion on Hydro One’s 2025 and 2024 consolidated financial statements, stating they present fairly in conformity with U.S. GAAP. They identified evaluation of regulatory assets and liabilities and the impact of rate regulation as a critical audit matter requiring complex judgment.

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