UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)


☑	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended	December 31, 2025


☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number: 001-32576

ITC HOLDINGS CORP.

(Exact Name of Registrant as Specified in Its Charter)


Michigan						32-0058047
(State or Other Jurisdiction of Incorporation or Organization)						(I.R.S. Employer Identification No.)

27175 Energy Way

Novi, Michigan 48377

(Address of Principal Executive Offices, Including Zip Code)

(248) 946-3000

(Registrant’s Telephone Number, Including Area Code)

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


Title of Each Class	Trading Symbol(s)	Name of Each Exchange on Which Registered
None	None	None

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes þ No o

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes o No þ

*The registrant is a voluntary filer and has not been subject to the filing requirements under Section 13 or 15(d) of the Securities Exchange Act of 1934 for the preceding 12 months.

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

Yes þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer

Accelerated
filer

Non-accelerated filer

Smaller reporting company

Emerging growth company

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

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

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

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DEFINITIONS

Unless otherwise noted or the context requires, all references in this report to:

ITC Holdings Corp. and its subsidiaries

•“ITC Great Plains” are references to ITC Great Plains, LLC, a wholly-owned subsidiary of ITC Holdings;

•“ITC Holdings” are references to ITC Holdings Corp., a wholly-owned subsidiary of ITC Investment Holdings, and not any of ITC Holdings’ subsidiaries;

•“ITC Michigan” are references to ITCTransmission and METC together;

•“ITC Midwest” are references to ITC Midwest LLC, a wholly-owned subsidiary of ITC Holdings;

•“ITCTransmission” are references to International Transmission Company, a wholly-owned subsidiary of ITC Holdings;

•“METC” are references to Michigan Electric Transmission Company, LLC, a wholly-owned subsidiary of MTH;

•“MISO Regulated Operating Subsidiaries” are references to ITCTransmission, METC and ITC Midwest together;

•“MTH” are references to Michigan Transco Holdings, LLC, the sole member of METC and a wholly-owned subsidiary of ITC Holdings;

•“Regulated Operating Subsidiaries” are references to ITCTransmission, METC, ITC Midwest, and ITC Great Plains together; and

•“Company,” “we,” “our” and “us” are references to ITC Holdings together with all of its subsidiaries.

Other definitions

•“ACPB” are references to the annual corporate performance bonus;

•“AFUDC” are references to an allowance for funds used during construction;

•“Ancillary Services Agreement” are references to the Amended and Restated Purchase and Sale Agreement for Ancillary Services entered into by METC and Consumers Energy dated as of April 29, 2002;

•“AOCI” are references to accumulated other comprehensive income or loss;

•“BA” are references to a Balancing Authority;

•“CIA” are references to the Coordination and Interconnection Agreement entered into by ITCTransmission and DTE Electric dated as of February 28, 2003;

•“CIO” are references to Chief Information Officer;

•“CODM” are references to Chief Operating Decision Maker;

•“Consumers Energy” are references to Consumers Energy Company, a wholly-owned subsidiary of CMS Energy Corporation;

•“D.C. Circuit Court” are references to the U.S. Court of Appeals for the District of Columbia Circuit;

•“DOE” are references to the Department of Energy;

•“DTE Electric” are references to DTE Electric Company, a wholly-owned subsidiary of DTE Energy;

•“DTE Energy” are references to DTE Energy Company;

•“DTIA” are references to the Distribution-Transmission Interconnection Agreement entered into by ITC Midwest and IP&L dated as of December 17, 2007 and amended and restated effective as of December 1, 2016;

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•“DT Interconnection Agreement” are references to the Amended and Restated Distribution-Transmission Interconnection Agreement entered into by METC and Consumers Energy dated April 1, 2001 and most recently amended and restated effective as of January 1, 2015;

•“Easement Agreement” are references to the Amended and Restated Easement Agreement entered into by METC and Consumers Energy dated April 29, 2002 and as further supplemented;

•“Eiffel” are references to Eiffel Investment Pte Ltd, a private limited company duly organized and validly existing under the laws of Singapore that is the GIC subsidiary that is a minority investor in ITC Investment Holdings and successor to Finn Investment Pte Ltd;

•“Exchange Act” are references to the Securities Exchange Act of 1934, as amended;

•“FASB” are references to the Financial Accounting Standards Board;

•“FERC” are references to the Federal Energy Regulatory Commission;

•“Formula Rate” are references to a FERC-approved formula template used to calculate an annual revenue requirement;

•“Fortis” are references to Fortis Inc.;

•“FortisUS” are references to FortisUS Inc., an indirect subsidiary of Fortis;

•“FPA” are references to the Federal Power Act;

•“GAAP” are references to accounting principles generally accepted in the United States of America;

•“Generator Interconnection Agreement” are references to the Amended and Restated Generator Interconnection Agreement entered into by Consumers Energy and METC dated as of April 29, 2002 and most recently amended effective as of November 1, 2018;

•“GIAs” are references to generator interconnection agreements;

•“GIC” are references to GIC Private Limited;

•“GIOA” are references to the Generator Interconnection and Operation Agreement entered into by DTE Electric and ITCTransmission dated as of February 28, 2003;

•“Initial Complaint” are references to a November 2013 complaint to the FERC under Section 206 of the FPA regarding the base ROE;

•“IP&L” are references to Interstate Power and Light Company, an Alliant Energy Corporation subsidiary;

•“ITC Investment Holdings” are references to ITC Investment Holdings Inc., a majority owned indirect subsidiary of Fortis in which GIC has an indirect, passive, non-voting minority ownership interest;

•“IUC” are references to the Iowa Utilities Commission;

•“KCC” are references to the Kansas Corporation Commission;

•“kV” are references to kilovolts (one kilovolt equaling 1,000 volts);

•“LGIA” are references to the Large Generator Interconnection Agreement entered into by ITC Midwest, IP&L, and MISO dated as of December 20, 2007 and amended as of August 2, 2017;

•“LRTP” are references to long-range transmission plan, an initiative to build transmission projects across the MISO region;

•“May 2020 Order” are references to an order issued by the FERC on May 21, 2020 regarding MISO ROE Complaints;

•“MECS” are references to the Michigan Electric Coordinated Systems;

•“MISO” are references to the Midcontinent Independent System Operator, Inc., a FERC-approved RTO which oversees the operation of the bulk power transmission system for a substantial portion of the Midwestern United States and Manitoba, Canada, and of which ITCTransmission, METC and ITC Midwest are members;

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•“MISO ROE Complaints” are references to the Initial Complaint and the Second Complaint;

•“MOA” are references to the Master Operating Agreement entered into by ITCTransmission and DTE Electric dated as of February 28, 2003;

•“NAV” are references to net asset value;

•“NERC” are references to the North American Electric Reliability Corporation;

•“NOLs” are references to net operating loss carryforwards for income taxes;

•“NOPR” are references to a Notice of Proposed Rulemaking issued by the FERC;

•“NYSE” are references to the New York Stock Exchange;

•“October 2024 Order” are references to an order issued by the FERC on October 17, 2024 regarding MISO ROE Complaints;

•“Operating Agreement” are references to the Amended and Restated Operating Agreement entered into by Consumers Energy and METC dated as of April 29, 2002;

•“OSA” are references to the Operations Services Agreement for 34.5 kV Transmission Facilities entered into by ITC Midwest and IP&L effective as of January 1, 2011;

•“PBU” are references to a performance-based unit;

•“ROE” are references to return on equity;

•“ROFR” are references to right of first refusal;

•“RTO” are references to Regional Transmission Organizations;

•“SBU” are references to a service-based unit;

•“SEC” are references to the Securities and Exchange Commission;

•“Second Complaint” are references to an additional complaint filed on February 12, 2015 with the FERC under Section 206 of the FPA regarding the base ROE;

•“Shareholders Agreement” are references to the Amended and Restated Shareholders’ Agreement, dated as of January 28, 2021 by and among the Company, ITC Investment Holdings, FortisUS, Eiffel (as successor to Finn Investment Pte Ltd), and any other person that becomes a shareholder of ITC Investment Holdings pursuant to such agreement;

•“SPP” are references to Southwest Power Pool, Inc., a FERC-approved RTO which oversees the operation of the bulk power transmission system for a substantial portion of the South Central United States, and of which ITC Great Plains is a member;

•“Sunflower” are references to Sunflower Electric Power Corporation;

•“Sunflower Agreement” are references to an Amended and Restated Maintenance Agreement entered into by Sunflower and ITC Great Plains dated as of August 24, 2010, and most recently amended effective as of September 26, 2025;

•“TO” are references to transmission owner;

•“TSR” are references to total shareholder return;

•“ULCS” are references to Utility Lines Construction Services, LLC, a division of Asplundh Tree Expert Co.; and

•“USD” are references to the United States dollar.

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PART I

ITEM 1. BUSINESS.

Overview

ITC Holdings and our Regulated Operating Subsidiaries provide safe and reliable electric transmission service to connect consumers to cost-effective energy resources. Our Regulated Operating Subsidiaries continue to make investments in a modernized grid to maintain reliability and accommodate future demands as lifestyles and the economy become increasingly dependent on electricity.

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

Our Regulated Operating Subsidiaries’ primary operating responsibilities include maintaining, improving and expanding their transmission systems to meet their customers’ ongoing needs, scheduling outages on system elements to allow for maintenance and construction, maintaining appropriate system voltages and monitoring flows over transmission lines and other facilities to ensure physical limits are not exceeded.

Our Regulated Operating Subsidiaries earn revenues for the use of their electric transmission systems by their customers, which include investor-owned utilities, municipalities, cooperatives, power marketers and alternative energy suppliers. As independent transmission companies, our Regulated Operating Subsidiaries are subject to rate regulation only by the FERC, and our cost-based rates are discussed in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cost-Based Formula Rates with True-Up Mechanism” as well as in Note 6 to the consolidated financial statements.

ITC Holdings is a wholly-owned subsidiary of ITC Investment Holdings. Fortis owns a majority indirect equity interest in ITC Investment Holdings, with GIC holding an indirect, passive, non-voting equity interest of 19.9%.

Development of Business

As we move toward an increasingly electrified and energy-intensive economy, the power grid will need to be transformed and modernized. Further, a secure and reliable grid is imperative to protect critical infrastructure and to promote economic development in the areas we serve. Technology deployment and innovation are occurring at an accelerated rate within our industry, so we are actively identifying and investing in infrastructure which leverages these advancements while meeting evolving system needs and energy policy objectives. Our long-term growth plan includes ongoing investments in our current regulated transmission systems and the identification of incremental strategic projects primarily located in and around our service territories. In addition, evolving technologies such as data centers, with increasing energy demand and load capacity requirements, will require electric transmission systems to adapt to future demands at a scale and pace beyond the historical trends of development.

We expect to invest approximately $7.3 billion from 2026 through 2030 at our Regulated Operating Subsidiaries. Included in this amount are capital expenditures to: (1) maintain and replace our current transmission infrastructure to enhance system reliability and accommodate load growth; (2) expand access to electricity markets to reduce the overall cost of delivered energy to customers and provide access to competitive markets for economic development; (3) interconnect new generation resources; and (4) upgrade physical and technological grid security to protect critical infrastructure.

Refer to “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Investment and Operating Results Trends” for additional details about our long-term capital investments. Refer to the discussion of risks associated with our strategic investment opportunities in “Item 1A. Risk Factors.”

Operations

As transmission-only companies, our Regulated Operating Subsidiaries function as conduits, allowing for power from generators to be transmitted to local distribution systems either entirely through our Regulated Operating Subsidiaries’ own systems or in conjunction with neighboring transmission systems. Third parties

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then transmit power through these local distribution systems to end-use consumers. The transmission of electricity by our Regulated Operating Subsidiaries is a central function to the provision of electricity to residential, commercial and industrial end-use consumers. The operations performed by our Regulated Operating Subsidiaries fall into the following categories:

•asset planning;

•engineering;

•safety, protection and preparedness;

•cyber security operations center; and

•real time operations.

Asset Planning

The Asset Planning group performs the role of detailing the required transmission infrastructure needed to support system changes and economic opportunities. System changes can arise from different points of origin including load growth, load shifts, or new points of interconnection; generation retirements or additions; operational needs; and system dynamic stability needs. Likewise, the Asset Planning group explores opportunities to better utilize the transmission system through economic planning by providing access, via transmission expansion projects, to lower cost energy. However, the core responsibility of the Asset Planning group is proactively anticipating the future demands placed upon the transmission system and developing corrective action plans for any deficiencies. Corrective action plans are developed to ensure compliance with NERC’s reliability standards. Additionally, the Asset Planning group seeks opportunities to further develop a resilient transmission system.

Transmission infrastructure plans are submitted as discrete projects into the MISO and SPP planning processes. As the regional planning authorities, MISO and SPP administer open and transparent processes through which the submitted projects are vetted. MISO and SPP produce transmission expansion plans, which include projects to be constructed by their members, including our Regulated Operating Subsidiaries.

Engineering

The Engineering group is composed of the Design, Capital Projects, Asset Management and System Protection and Control teams. The Engineering group works with outside contractors to perform various aspects of our design, construction and maintenance activities, but retains internal technical experts who have experience with respect to the key elements of the transmission system such as substations, lines, equipment and protective relaying systems.

The Design team is responsible for the design of our transmission systems and maintaining the standards for equipment used on our systems. The team is also responsible for preparing project cost estimates.

The Capital Projects team is responsible for project and construction management, including field oversight for capital projects and associated forecasting, which includes the construction of new transmission infrastructure as well as asset renewal projects.

The Asset Management team is responsible for managing our vegetation management program, providing engineering technical support to the field and specifying, maintaining and troubleshooting substation and transmission line assets.

The System Protection and Control team is responsible for specifying, maintaining, and troubleshooting protection and Supervisory Control and Data Acquisition systems that are used to protect, monitor and operate our transmission infrastructure.

Together, the Asset Management and the System Protection and Control teams develop and track preventative maintenance to promote safe and reliable systems adhering to mandatory requirements of the NERC and the FERC.

By performing preventive maintenance on our assets, we can minimize the need for reactive maintenance, resulting in improved reliability and cost savings for our customers. Our Regulated Operating Subsidiaries contract with ULCS to perform the majority of their maintenance. The agreement with ULCS provides us with access to an experienced and scalable workforce with knowledge of our system at an established rate.

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Safety, Protection and Preparedness

The Safety, Protection and Preparedness group supports the well-being of our employees, contractors, and the public by embedding safety, human performance, physical security, and emergency readiness into our operations. Given the inherent hazardous nature of the utilities industry, we proactively create environments where people can perform safely while delivering reliable electric transmission services.

Our safety system is built on human performance principles that strengthen our safety culture. We respond when needed utilizing an incident command structure and maintain comprehensive emergency response plans in an effort to ensure business continuity. From our Michigan headquarters, our security command center monitors critical assets, gathers intelligence and collaborates with government and industry partners to detect and prevent threats.

Cyber Security Operations Center

The Cyber Security Operations Center protects our business and reputation by securing critical infrastructure, data and computing systems from threat actors. This group protects vital infrastructure by developing, refining and continually delivering a comprehensive cybersecurity program while helping stakeholders meet business objectives. See “Item 1C. Cybersecurity” for additional information on our cybersecurity governance, risks and mitigation strategies.

Real Time Operations

System Operations — From our control centers in Michigan, transmission system operators continuously monitor the performance of the transmission systems of our Regulated Operating Subsidiaries, using software and communication systems to perform real-time analysis to proactively manage contingencies and maintain security and reliability on a continuous basis. Transmission system operators are also responsible for the switching and protective tagging function, taking equipment in and out of service to ensure capital construction projects and maintenance programs can be completed safely and reliably.

Balancing Authority Operator — Under the functional control of MISO, ITCTransmission and METC operate their electric transmission systems as a combined BA area, known as MECS. From our control centers in Michigan, our employees perform the BA functions as outlined in MISO’s Balancing Authority Agreement on a continuous basis. These functions include actual interchange data administration and verification as well as MECS BA area emergency procedure implementation and coordination. No other Regulated Operating Subsidiaries are responsible for BA functions for their respective assets.

Operating Contracts

Our Regulated Operating Subsidiaries have various operating contracts, including numerous interconnection agreements with generation and transmission providers that address terms and conditions of interconnection. The following significant agreements exist at our Regulated Operating Subsidiaries:

ITCTransmission

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

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

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

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

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METC

Consumers Energy operates an electric distribution system that is interconnected with METC’s transmission system. METC is a party to a number of operating contracts with Consumers Energy that govern the operations and maintenance of its transmission system. These contracts include the following:

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

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

Amended and Restated Distribution-Transmission Interconnection Agreement. The DT Interconnection Agreement provides for the interconnection of Consumers Energy’s distribution system with METC’s transmission system and defines the continuing rights, responsibilities and obligations of the parties with respect to the use of certain of their own and the other party’s properties, assets and facilities.

Amended and Restated Generator Interconnection Agreement. The Generator Interconnection Agreement specifies the terms and conditions under which Consumers Energy and METC maintain the interconnection of Consumers Energy’s generation resources and METC’s transmission assets.

ITC Midwest

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

Distribution-Transmission Interconnection Agreement. The DTIA governs the rights, responsibilities and obligations of ITC Midwest and IP&L, with respect to the use of certain of their own and the other party’s property, assets and facilities and the construction of new facilities or modification of existing facilities.

Large Generator Interconnection Agreement. ITC Midwest, IP&L and MISO entered into the LGIA in order to establish and maintain the direct electricity interconnection of IP&L’s electricity generating assets with ITC Midwest’s transmission system for the purposes of transmitting electric power from and to the electricity generating facilities.

Operations Services Agreement For 34.5 kV Transmission Facilities. ITC Midwest and IP&L entered into the OSA under which IP&L performs certain operations functions for ITC Midwest’s 34.5 kV transmission system.

ITC Great Plains

Amended and Restated Maintenance Agreement. Sunflower and ITC Great Plains have entered into the Sunflower Agreement pursuant to which Sunflower has agreed to perform various field operations and maintenance services related to certain ITC Great Plains assets.

Regulatory Environment

Many regulators and public policy makers support the need for further investment in the transmission grid considering demand growth driven by energy-intensive industries alongside an evolving electricity generation mix. These emerging trends, combined with historically inadequate transmission investment, have resulted in

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capacity constraints across the United States and increased stress on aging equipment. These challenges will continue without increased investment in transmission infrastructure. Transmission system investments can also increase system reliability and reduce the frequency of power outages. Such investments can reduce transmission constraints and improve access to lower cost generation resources, resulting in a lower overall cost of delivered electricity for end-use consumers. The DOE has established the Office of Electricity that focuses on working with reliability experts from the power industry, state governments and their Canadian counterparts to improve grid reliability and increase investment in the country’s electric infrastructure.

The FERC requires TOs to comply with certain reliability standards and may take enforcement actions for violations, including the imposition of substantial fines. NERC is responsible for developing and enforcing these mandatory reliability standards. We continually assess our transmission systems against standards established by NERC, as well as the standards of applicable regional entities under NERC that have been delegated certain authority for the purpose of proposing and enforcing reliability standards.

Finally, utility holding companies are subject to FERC regulations related to access to books and records in addition to the requirement of the FERC to review and approve mergers and consolidations involving utility assets and holding companies in certain circumstances.

Federal Regulation

As electric transmission companies, our Regulated Operating Subsidiaries charge rates that are regulated by the FERC. The FERC is an independent regulatory commission within the DOE that regulates the interstate transmission and certain wholesale sales of natural gas, the transmission of oil and oil products by pipeline and the transmission and wholesale sales of electricity in interstate commerce. The FERC also administers accounting and financial reporting regulations and standards of conduct for the companies it regulates.

Revenue Requirement Calculations and Cost Sharing for Projects with Regional Benefits

The cost-based Formula Rates used by our Regulated Operating Subsidiaries include revenue requirement calculations for various types of projects. Network revenues continue to be the largest component of revenues recovered through our Formula Rates. However, regional cost sharing revenues have experienced long-term growth as a result of projects that have been identified as having regional benefits and are therefore eligible for regional cost recovery. Separate calculations of revenue requirement are performed for projects that have been approved for regional cost sharing.

We have projects that are eligible for regional cost sharing under the MISO tariff, such as certain network upgrade projects. Additionally, certain projects at ITC Great Plains are eligible for recovery through a region-wide charge pursuant to the SPP tariff.

State Regulation and Local Zoning Authority

The regulatory agencies in the states where our Regulated Operating Subsidiaries’ assets are located do not have jurisdiction over our rates or terms and conditions of service. However, they typically have jurisdiction over siting of transmission facilities and related matters as described below. Local authorities may also have jurisdiction over zoning approval for certain projects. Additionally, we are subject to the regulatory oversight of various state environmental quality departments for compliance with any state environmental standards and regulations.

ITCTransmission and METC

Michigan

The Michigan Public Service Commission has jurisdiction over the siting of certain transmission facilities. Additionally, ITCTransmission and METC have the right as independent transmission companies to condemn property in the state of Michigan for the purposes of building or maintaining transmission facilities.

ITCTransmission and METC are also subject to the regulatory oversight of certain state agencies (including the Michigan Department of Natural Resources and the Michigan Department of Environment, Great Lakes & Energy) along with certain local authorities with respect to the issuance of environmental, highway, railroad and other applicable permits.

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ITC Midwest

Iowa

The IUC has jurisdiction over the construction, operation and maintenance of transmission facilities in Iowa by any entity, which includes the power to issue franchises. Iowa law further provides that any entity granted a franchise by the IUC is vested with the power of condemnation in Iowa to the extent the IUC approves and deems necessary for public use. A city has the power, pursuant to Iowa law, to grant a franchise to erect, maintain and operate transmission facilities within the city limits, which franchise may regulate the conditions required and manner of use of the streets and public grounds of the city and may confer the power to appropriate and condemn private property.

ITC Midwest also is subject to the regulatory oversight of certain state agencies (including the Iowa Department of Natural Resources) and certain local authorities with respect to the issuance of environmental, highway, railroad and similar permits.

Minnesota

The Minnesota Public Utilities Commission has jurisdiction over the construction, siting and routing of new transmission lines and upgrades to existing lines through Minnesota’s Certificate of Need and Route Permit Processes. Transmission companies are also required to participate in the state’s Biennial Transmission Planning Process and are subject to the state’s preventative maintenance requirements. Pursuant to Minnesota law, ITC Midwest has the right as an independent transmission company to condemn property in the state of Minnesota for the purpose of building new transmission facilities.

ITC Midwest is also subject to the regulatory oversight of the Minnesota Pollution Control Agency, the Minnesota Department of Natural Resources, the Minnesota Public Utilities Commission in conjunction with the Department of Commerce and certain local authorities for compliance with applicable environmental standards and regulations.

Illinois

ITC Midwest is a “public utility” in Illinois. The Illinois Commerce Commission exercises jurisdiction over the siting of new transmission lines through its requirements for Certificates of Public Convenience and Necessity and Right-Of-Way acquisition that apply to construction of new and upgraded facilities.

ITC Midwest is also subject to the regulatory oversight of the Illinois Environmental Protection Agency, the Illinois Department of Natural Resources, the Illinois Pollution Control Board and certain local authorities for compliance with all environmental standards and regulations.

Missouri

ITC Midwest is a “public utility” and an “electrical corporation” under Missouri law. The Missouri Public Service Commission has jurisdiction to determine whether ITC Midwest may operate in such capacity. The Missouri Public Service Commission also exercises jurisdiction with regard to other non-rate matters affecting its sole Missouri asset such as transmission substation construction, general safety and the transfer of the franchise or property.

ITC Midwest is also subject to the regulatory oversight of the Missouri Department of Natural Resources for compliance with all environmental standards and regulations relating to this transmission line.

Wisconsin

ITC Midwest is a “public utility” and independent TO in Wisconsin. The Public Service Commission of Wisconsin granted ITC Midwest a certificate of authority to transact public utility business in the state. The Public Service Commission of Wisconsin also recognized ITC Holdings as a public utility holding company under Wisconsin statutes.

The Public Service Commission of Wisconsin exercises jurisdiction over the siting of new transmission lines through the issuance of certificates of authority and certificates of public convenience and necessity. Upon receipt of such certificates for a transmission project, ITC Midwest has condemnation authority as a foreign transmission provider under Wisconsin law. ITC Midwest is also subject to the jurisdiction of certain local and

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state agencies, including the Wisconsin Department of Natural Resources, relating to environmental and road permits.

ITC Great Plains

Kansas

ITC Great Plains is a “public utility” and an “electric utility” in Kansas pursuant to state statutes. The KCC issued an order approving the issuance of a limited certificate of convenience to ITC Great Plains for the purposes of building, owning and operating SPP transmission projects in Kansas. In addition to its certificate of authority, the KCC has jurisdiction over the siting of electric transmission lines.

ITC Great Plains is also subject to the regulatory oversight of the Kansas Department of Health and Environment for compliance with all environmental standards and regulations relating to the construction phase of any transmission line.

Oklahoma

ITC Great Plains has approval from the Oklahoma Corporation Commission to operate in Oklahoma, pursuant to Oklahoma statutes as an electric public utility providing only transmission services. The Oklahoma Corporation Commission has jurisdiction over processes for certification of certain transmission lines.

ITC Great Plains is subject to the regulatory oversight of Oklahoma Department of Environmental Quality for compliance with environmental standards and regulations relating to construction and decommissioning of certain proposed transmission facilities.

Sources of Revenue

See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Significant Components of Results of Operations — Revenues” for a discussion of our principal sources of revenue.

Seasonality

The cost-based Formula Rates in effect for our Regulated Operating Subsidiaries mitigate the seasonality of our net income. Our Regulated Operating Subsidiaries accrue or defer revenues to the extent that the actual revenue requirement for the reporting period is higher or lower, respectively, than the amounts billed relating to that reporting period. For example, to the extent that amounts billed are less than our revenue requirement for a reporting period, a revenue accrual is recorded for the difference and the difference results in no net income impact. Refer to “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Revenue Accruals and Deferrals — Effects of Monthly Network Peak Loads” for further discussion of the impact of revenue accruals and deferrals. Operating cash flows are seasonal at our MISO Regulated Operating Subsidiaries, in that cash received for revenues is typically higher in the summer months when peak load is higher.

Principal Customers

Our principal transmission service customers are DTE Electric, Consumers Energy and IP&L, which accounted for approximately 23.0%, 22.4% and 21.7%, respectively, of our consolidated billed revenues for the year ended December 31, 2025. These customers, together and individually, consistently represent a significant percentage of our operating revenues. This portion of total billed revenues of DTE Electric, Consumers Energy and IP&L include the net refund of 2023 revenue accruals and deferrals and exclude any amounts for the 2025 revenue accruals and deferrals that were included in our 2025 operating revenues but will not be billed to our customers until 2027. See Note 6 to the consolidated financial statements for a discussion on the difference between billed revenues and operating revenues. Our remaining revenues were generated from providing service to other entities such as alternative energy suppliers, power marketers and other wholesale customers that provide electricity to end-use consumers and from transaction-based capacity reservations. Nearly all of our revenues are from transmission customers in the United States. Although we may recognize allocated revenues from time to time from Canadian entities reserving transmission over the Ontario or Manitoba interface, these revenues have not been and are not expected to be material to us.

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Billing

MISO and SPP are responsible for billing and collecting the majority of our transmission service revenues as well as independently administering the transmission tariff in their respective service territory. As the billing agents for our MISO Regulated Operating Subsidiaries and ITC Great Plains, MISO and SPP independently bill DTE Electric, Consumers Energy, IP&L and other customers on a monthly basis and collect fees for the use of our transmission systems.

See “Item 7A. Quantitative and Qualitative Disclosures about Market Risk — Credit Risk” for discussion of our credit policies.

Competition

Each of our MISO Regulated Operating Subsidiaries operates the primary transmission system in its respective service area and has limited competition for certain projects. While we have rights of first refusal to build projects in certain states in which we operate, other entities with transmission development initiatives may compete with us by seeking approval to be named the party authorized to build new capital projects that we are also pursuing. Our subsidiaries may also compete with other entities on development opportunities for transmission investment in locations outside of our existing service areas.

Human Capital Resources

ITC Holdings places significant emphasis on attracting, developing and retaining individuals who exemplify the values that are the cornerstone of our company. As of December 31, 2025, we had 868 employees with low turnover. None of our employees are covered by collective bargaining agreements. In addition, we work with many outside firms to provide additional resources to support our business. We utilize human capital resources employed by these firms to assist with construction, maintenance, field operations and other corporate functions of our business. We believe that we have good relationships with our suppliers of contracted services.

Safety is of the utmost importance for our employees, and we consider safety to be a key priority for our company. Our safety policies, procedures and training practices have resulted in safety performance metrics that consistently rank us in the top decile among comparable electric utilities.

We believe that our compensation and benefit programs have been appropriately designed to attract and retain talent. Compensation for employees is made up of a combination of base salary, short-term incentive and long-term incentive pay structures. In addition, we offer a comprehensive package of additional health and welfare, retirement and wellness benefits for all of our employees and various professional development opportunities through internal and external programs. We value all of our employees and our company culture promotes employee engagement. We believe that by recognizing and valuing our employees we make our shared goals possible.

Environmental Matters

See “Environmental Matters” in Note 17 to the consolidated financial statements.

Available Information Under the Securities Exchange Act of 1934

Our Internet address is http://www.itc-holdings.com. Visit our website to learn more about us. Financial and other material information regarding us is routinely posted on our website and is readily accessible. We are a voluntary filer and are not subject to the filing requirements under Section 13 or 15(d) of the Exchange Act. However, all of our reports filed pursuant to Section 13(a) or 15(d) of the Exchange Act, including our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports, can be accessed free of charge through our website. These reports are available as soon as practicable after they are electronically filed with the SEC. The information on our website is not incorporated by reference into this report.

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ITEM 1A. RISK FACTORS.

Risks Related to Our Business

Certain elements of our Regulated Operating Subsidiaries’ Formula Rates have been and can be challenged, which could result in lowered rates and/or refunds of amounts previously collected and thus may have an adverse effect on our business, financial condition, results of operations and cash flows.

Our Regulated Operating Subsidiaries provide transmission service under rates regulated by the FERC. The FERC has approved the cost-based Formula Rates used by our Regulated Operating Subsidiaries to calculate their respective annual revenue requirements, but it has not expressly approved the amount of actual capital and operating expenditures to be used in the Formula Rates. All aspects of our Regulated Operating Subsidiaries’ rates approved by the FERC, including the Formula Rate templates, the rates of return on the actual equity portion of their respective capital structures, ROE adders for independent transmission ownership and RTO participation, the approved capital structures and other aspects of our rates, are subject to challenge by interested parties at the FERC, or by the FERC on its own initiative in a proceeding under Section 206 of the FPA. In addition, interested parties may challenge the annual implementation and calculation by our Regulated Operating Subsidiaries of their projected rates and Formula Rate true up pursuant to their approved Formula Rates under the Regulated Operating Subsidiaries’ Formula Rate implementation protocols. End-use consumers and entities supplying electricity to end-use consumers may also attempt to influence government and/or regulators to change the rate setting methodologies that apply to our Regulated Operating Subsidiaries, particularly if rates for delivered electricity increase substantially. If a challenger can establish that any of these aspects are unjust, unreasonable, unduly discriminatory or preferential, then the FERC will make adjustments to them and/or disallow any of our Regulated Operating Subsidiaries’ inclusion of those aspects in the rate setting formula. This could result in lowered rates and/or refunds of amounts collected, any of which could have a material adverse effect on our business, financial condition, results of operations and cash flows. See “Rate of Return on Equity Complaints” in Note 17 to the consolidated financial statements for detail on ROE matters.

Our actual capital investment may be lower than planned, which would cause a lower than anticipated rate base and would therefore result in lower revenues, earnings and associated cash flows compared to our current expectations. In addition, shifts in federal, state, or regulatory policies promoting increased competition, including competitive bid projects, may decrease future capital investment opportunities outside our five-year capital investment plan.

Each of our Regulated Operating Subsidiaries’ rate base, revenues, earnings and associated cash flows are determined in part by additions to property, plant and equipment and when those additions are placed in service. If our operating subsidiaries’ capital investment and the resulting in-service property, plant and equipment are lower than anticipated for any reason, our operating subsidiaries will have a lower than anticipated rate base, thus causing their revenue requirements and future earnings and cash flows to be lower than anticipated.

Any capital investment at our Regulated Operating Subsidiaries may be lower than our published estimates or future expectations due to, among other factors, the impact of:

•actual or forecasted loads;

•regional economic conditions;

•weather conditions;

•union strikes or labor shortages;

•material and equipment prices and availability;

•variances between estimated and actual costs of construction contracts awarded;

•our ability to obtain financing for such expenditures, if necessary;

•limitations on the amount of construction that can be undertaken on our system or transmission systems owned by others at any one time;

•regulatory requirements relating to our rate construct, including our ability to recover costs;

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•the potential for greater competition, including the effects of pursuing competitive bid projects;

•environmental, siting or regional planning issues; and

•legal proceedings.

Our ability to engage in construction projects resulting from pursuing these initiatives is subject to significant uncertainties, including the factors discussed above, and also depends on obtaining any necessary regulatory and other approvals for a project and for us to initiate construction, our achieving status as the builder of the project in some circumstances and other factors. Even if we engage in construction projects, such projects may be canceled, the scope of planned projects may change, the actual costs of such projects may be more than expected, or projects may not be completed on time, any of which may adversely affect our level of investment, cause our projected investments to be inaccurate or adversely affect our future results of operations, cash flows and financial condition. Moreover, the competitive bidding of transmission projects may result in state and federal policy changes going forward.

In addition, we may incur expenses to pursue strategic investment opportunities, even if such opportunities are not ultimately engaged. If these payments or expenses are higher than anticipated, or are incurred without engaging in such opportunity, our future results of operations, cash flows and financial condition could be materially and adversely affected.

See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Investment and Operating Results Trends” for a discussion of our actual and expected capital expenditures at our Regulated Operating Subsidiaries.

The regulations to which we are subject may limit our ability to raise capital and/or pursue acquisitions, development opportunities or other transactions or may subject us to liabilities.

Each of our Regulated Operating Subsidiaries is a “public utility” under the FPA and, accordingly, is subject to regulation by the FERC. Approval by the FERC is required under Section 203 of the FPA for a disposition or acquisition of regulated public utility facilities, either directly or indirectly through a holding company. Such approval is also required to acquire a significant interest in securities of a public utility. Section 203 of the FPA also provides the FERC with explicit authority over utility holding companies’ purchases or acquisitions of, and mergers or consolidations with, a public utility. Finally, each of our Regulated Operating Subsidiaries must also seek approval by the FERC under Section 204 of the FPA for issuances of its securities (including debt securities). If we are unable to obtain the necessary FERC approvals for potential acquisitions, dispositions or merger activities, or to raise capital, our strategic and growth opportunities may be limited. This could have an adverse impact on our financial condition, results of operations and cash flows.

We are also pursuing development projects for construction of transmission facilities and interconnections with generating resources. These projects may require regulatory approval by Federal agencies, including the FERC, applicable RTOs and state and local regulatory agencies. Failure to secure such regulatory approval for new strategic development projects could adversely affect our ability to grow our business and increase our revenues. If we fail to obtain these approvals when necessary, we may incur liabilities for such failure.

Changes in energy laws, regulations or policies could impact our business, financial condition, results of operations and cash flows.

Each of our Regulated Operating Subsidiaries is regulated by the FERC as a “public utility” under the FPA and is a TO in MISO or SPP. We cannot predict whether the approved rate methodologies for any of our Regulated Operating Subsidiaries will be changed. In addition, the U.S. government could assign new responsibilities to the FERC, modify provisions of the FPA or provide the FERC or another entity with changes to authority to regulate transmission matters. Our Regulated Operating Subsidiaries may be affected by any such changes in federal energy laws, regulations or policies in the future. While our Regulated Operating Subsidiaries are subject to the FERC’s exclusive jurisdiction for purposes of rate regulation, changes in state laws affecting other matters, such as transmission siting and construction, could limit investment opportunities available to us.

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Each of our MISO Regulated Operating Subsidiaries depends on its primary customer for a substantial portion of its revenues, and any material failure by those primary customers to make payments for transmission services could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Each of ITCTransmission, METC and ITC Midwest derive a substantial portion of their revenues from the transmission of electricity to the local distribution facilities of DTE Electric, Consumers Energy and IP&L, respectively. Each of these customers is expected to constitute the majority of the revenues of the respective MISO Regulated Operating Subsidiary for the foreseeable future. Any material failure by DTE Electric, Consumers Energy or IP&L to make payments for transmission services could have an adverse effect on our business, financial condition, results of operations and cash flows.

A significant amount of the land on which our assets are located is subject to easements, mineral rights and other similar encumbrances. As a result, we must comply with the provisions of various easements, mineral rights and other similar encumbrances, which may adversely impact our ability to complete construction projects in a timely manner.

METC does not own the majority of the land on which its electric transmission assets are located. Instead, under the provisions of the Easement Agreement, METC pays an annual rent to Consumers Energy in exchange for rights-of-way, leases, fee interests and licenses which allow METC to use the land on which its transmission lines are located. Under the terms of the Easement Agreement, METC’s easement rights could be eliminated if METC fails to meet certain requirements, such as paying contractual rent to Consumers Energy in a timely manner. Additionally, a significant amount of the land on which our other subsidiaries’ assets are located is subject to easements, mineral rights and other similar encumbrances. As a result, they must comply with the provisions of various easements, mineral rights and other similar encumbrances, which may adversely impact their ability to complete their construction projects in a timely manner.

We contract with third parties to provide services for certain aspects of our business. If any of these agreements are terminated, we may face a shortage of labor or replacement contractors to provide the services formerly provided by these third parties.

We enter into various agreements and arrangements with third parties to provide services for construction, maintenance and operations of certain aspects of our business, and we utilize the services of contractors to a significant extent. If any of these agreements or arrangements is terminated for any reason, it could result in a shortage of a readily available workforce to provide such services and we may face difficulty finding a qualified replacement workforce. In such a situation, if we are unable to find adequate replacements for contractors in a timely manner, it could have an adverse effect on our results of operations and the ability to carry on our business.

Hazards associated with high-voltage electricity transmission may result in suspension of our operations, costly litigation or the imposition of civil or criminal penalties.

Our operations are subject to the usual hazards associated with high-voltage electricity transmission, including explosions, fires, mechanical failure, unscheduled downtime, equipment interruptions, remediation, chemical spills, discharges or releases of toxic or hazardous substances or gases and other environmental risks. These hazards can cause personal injury and loss of life, severe damage to or destruction of property and equipment and environmental damage, and may result in suspension of operations, litigation by aggrieved parties and the imposition of civil or criminal penalties which may have a material adverse effect on our business, financial condition and results of operations. We are not fully insured against all potential hazards incident to our business, such as damage to poles, towers and lines or losses caused by outages. The costs of repairing such damage may exceed the insurance limits on our insurance policies or may be outside the coverage afforded by our insurance policies; and significant repair costs or continuous damage events could cause our insurance premiums to increase or lead to insurance coverage not being available at all.

A cyber-attack or incident could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Various U.S. Government agencies have noted that external threat sources continue to seek to exploit, through cyber-attacks, potential vulnerabilities in the U.S. energy infrastructure, including electric transmission assets. These cyber threats and attacks are becoming more sophisticated and dynamic, including as a result of

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the advancement of technologies like artificial intelligence, which malicious third parties are using to create new, sophisticated and more frequent attacks. Cybersecurity incidents could harm our business by limiting our transmission capabilities, delay our development and construction of new facilities or capital improvement projects on existing facilities or expose us to liability. Cyber-attacks targeting our information systems could also impair our records, networks, systems and programs, or transmit viruses to other systems. Such events or the threat of such events may increase costs associated with heightened security requirements. In addition, if our major customers or suppliers experience a cyber-attack it may reduce their ability to use our transmission facilities or service our transmission assets. If our business or those of our customers and suppliers are subject to a cyber-attack, it may have a material adverse effect on our business, financial condition, results of operations and cash flows. We may also need to obtain additional insurance coverage related to cyber threats and attacks. In addition, laws and regulations governing cybersecurity, data privacy and protection, and the unauthorized disclosure of confidential or protected information pose increasingly complex compliance challenges and potentially elevate costs, and any failure to comply with these laws and regulations could result in significant penalties and legal liability.

We are subject to environmental regulations and to laws that can give rise to substantial liabilities from environmental contamination.

We are subject to federal, state and local environmental laws and regulations, which impose limitations on the discharge of pollutants into the environment, establish standards for the management, treatment, storage, transportation and disposal of solid and hazardous wastes and hazardous materials, and impose obligations to investigate and remediate contamination in certain circumstances. Liabilities relating to investigation and remediation of contamination, as well as other liabilities concerning hazardous materials or contamination such as claims for personal injury or property damage, may arise at many locations, including formerly owned or operated properties and sites where wastes have been treated or disposed of, as well as properties we currently own or operate. Such liabilities may arise even where the contamination does not result from noncompliance with applicable environmental laws. Under a number of environmental laws, such liabilities may also be joint and several, meaning that a party can be held responsible for more than its share of the liability involved, or even the entire share.

We may be required to incur significant unanticipated expenses in connection with environmental compliance. Failure to comply with the extensive environmental laws and regulations applicable to us could result in significant civil or criminal penalties and remediation costs. Our assets and operations also involve the use of materials classified as hazardous, toxic or otherwise dangerous. Some of our facilities and properties are located near environmentally sensitive areas such as wetlands and habitats of endangered or threatened species. In addition, certain properties in which we operate are, or are suspected of being, affected by environmental contamination. Compliance with these laws and regulations, and liabilities concerning contamination or hazardous materials, may adversely affect our costs and, therefore, our business, financial condition and results of operations.

If amounts billed for transmission service for our Regulated Operating Subsidiaries’ transmission systems are lower than expected, or our actual revenue requirements are higher than expected, the timing of actual collection of our total revenues would be delayed.

If amounts billed for transmission service are lower than expected, the timing of actual collections of our Regulated Operating Subsidiaries’ total revenue requirement would likely be delayed until such circumstances are adjusted through the true-up mechanism, which would be settled within a two-year period, in our Regulated Operating Subsidiaries’ Formula Rates. Lower than expected amounts collected could result from lower network load or point-to-point transmission service on our Regulated Operating Subsidiaries’ transmission systems due to a weak economy, changes in the nature or composition of the transmission assets of our Regulated Operating Subsidiaries and surrounding areas, poor transmission quality of neighboring transmission systems, or for any other reason. In addition, if the revenue requirements of our Regulated Operating Subsidiaries are higher than expected, the timing of actual collection of our Regulated Operating Subsidiaries' total revenue requirements would likely be delayed until such circumstances are reflected through the true-up mechanism, which would be settled within a two-year period, in our Regulated Operating Subsidiaries' Formula Rates. This could be due to higher actual expenditures compared to the forecasted expenditures used to develop their billing rates or for any other reason. The effect of such under-collection would be to reduce the amount of our available cash resources from what we had expected, until such under-collection is corrected through the true-

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up mechanism in the Formula Rate template, which may require us to increase our outstanding indebtedness, thereby reducing our available borrowing capacity, and may require us to pay interest at a rate that exceeds the interest to which we are entitled in connection with the operation of the true-up mechanism.

Natural disasters, severe weather and other related phenomena, including those due to climate change, and the regulatory and legislative developments related to climate change, may have a material adverse effect on our business, financial condition, results of operations and cash flows.

Natural disasters, severe weather, and other related phenomena, primarily in the form of wildfires, thunderstorms, flooding, hurricanes, storm surges, atmospheric rivers and snow, ice storms, wind events or droughts, including those due to climate change, and the frequency and severity thereof, may negatively affect our business and financial condition through increased costs from (i) repairs to our transmission facilities, (ii) implementation of contingency plans for continued operations as repairs are underway and (iii) fluctuating energy use by customers, which may require us to invest in additional assets. We could also experience disruptions to our supply chain, as our suppliers may face similar challenges to their operations from such weather-related events due to climate change. The combination of climate change and the failure to adequately address the risk of wildfires within our existing service areas could result in civil liability arising out of government enforcement actions, inability to maintain adequate insurance coverage, regulatory recovery risk, negative impacts to credit ratings resulting in higher cost and/or less availability of new long-term debt and indeterminable litigation costs or adverse outcomes associated with defending against private claims. Prolonged power outages to customers and business interruptions from delays in storm restoration efforts could damage our reputation and may have a material adverse effect on our business, financial condition, results of operations and cash flows. Longer-term climate change impacts, such as sustained higher temperatures, higher sea levels, larger storm surges and floods, could result in service disruption, shortened asset life, increased repair and replacement costs, and costs associated with strengthened design standards and systems.

In addition to the physical effects of climate change, federal, regional or state legislative or regulatory bodies have attempted, and may in the future attempt, to introduce requirements or incentives to reduce peak demand and energy consumption or control or limit the causes of climate change, including greenhouse gas emissions, such as carbon dioxide and methane. Resulting programs, laws or regulations could lead to load reduction, or impose costs tied to greenhouse gas emissions, operational requirements or restrictions, or additional charges to fund energy efficiency activities or conservation measures. They could also provide a cost advantage to alternative energy sources or result in other costs or requirements, such as costs associated with the adoption of new infrastructure and technology to respond to new mandates. The occurrence of the foregoing events could put upward pressure on costs, adversely affecting our business, financial condition, results of operations and cash flows.

We are subject to various regulatory requirements, including reliability standards; contract filing requirements; reporting, recordkeeping and accounting requirements; and transaction approval requirements. Violations of these requirements, whether intentional or unintentional, may result in penalties that, under some circumstances, could have a material adverse effect on our business, financial condition, results of operations and cash flows.

The various regulatory requirements to which we are subject include reliability standards established by the NERC, which operates as the nation’s Electric Reliability Organization approved by the FERC in accordance with Section 215 of the FPA. These standards address operation, planning and security of the bulk power system, including requirements with respect to real-time transmission operations, emergency operations, vegetation management, critical infrastructure protection and personnel training. Failure to comply with these requirements can result in monetary penalties as well as non-monetary sanctions. Monetary penalties vary based on an assigned risk factor for each potential violation, the severity of the violation and various other circumstances, such as whether the violation was intentional or concealed, whether there are repeated violations, the degree of the violator’s cooperation in investigating and remediating the violation and the presence of a compliance program, and such penalties can be substantial. Non-monetary sanctions include potential limitations on the violator’s activities or operations and placing the violator on a watchlist for major violators. If any of our subsidiaries violate the NERC reliability standards, even unintentionally, in any material way, any penalties or sanctions imposed against us could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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Certain of our subsidiaries are also subject to requirements under Sections 203 and 205 of the FPA for approval of transactions; reporting, recordkeeping and accounting requirements; and for filing contracts related to the provision of jurisdictional services. Under FERC policy, failure to file jurisdictional agreements on a timely basis may result in foregoing the time value of revenues collected under the agreement, but not to the point where a loss would be incurred. The failure to obtain timely approval of transactions subject to FPA Section 203, or to comply with applicable reporting, recordkeeping or accounting requirements under FPA Section 205, could subject us to penalties that could have a material adverse effect on our financial condition, results of operations and cash flows.

Changes in tax laws or regulations may negatively affect our financial condition, results of operations, net income, cash flows and credit metrics.

We are subject to taxation by various taxing authorities at the federal, state and local levels. Various representatives of the government, corporations, industry groups and the public continue to pursue changes to tax laws and regulations, and corporate tax reform continues to be a priority in many jurisdictions. Due to unique aspects of the treatment of taxes for regulated utilities, the impacts of changes in tax laws for us and our Regulated Operating Subsidiaries may differ from the impacts to other corporations generally. Changes in federal, state or local tax rates or other aspects of tax laws could materially and adversely affect our financial condition, results of operations, net income, cash flows, and credit metrics.

The widespread outbreak of an illness or other communicable disease, or any other public health crisis, could have a material adverse impact on our business, financial condition, results of operations, cash flows and credit metrics.

We could be negatively impacted by the widespread outbreak of an illness or other communicable disease, or other public health crisis, that results in economic and trade disruptions, including the disruption of global supply chains. As a result of efforts to limit the spread of communicable diseases, public health authorities, OSHA, and/or the states served by our transmission systems may issue orders that can place restrictions on and/or result in the temporary shutdown of operations of businesses that use our transmission systems. Moreover, we may be required to comply with obligations enacted by relevant authorities to help prevent the spread of illness or disease, which poses the risk of workforce disruption that could impact business continuity. The impact of efforts to limit the spread of illness or disease on our business, financial condition and results of operations may be material and adverse and may depend on various factors. These factors may include the duration and severity of the illness or disease, the length and magnitude of any business restrictions that are enacted and the efficacy of other efforts to prevent the spread of the disease, such as vaccines.

The widespread outbreak of an illness or disease could also disrupt the supply chains that provide services and equipment to us as part of our capital expenditures or maintenance efforts. If our supply chains are disrupted, we may be unable to perform necessary maintenance, which could result in increased costs as we implement contingency plans to allow us to continue to operate. Supply chain interruptions may also increase the cost of capital expenditures or result in the delay or cancellation of planned projects, any of which could have a material adverse impact on our business, financial condition, results of operations and cash flows.

We require access to the capital markets to fund capital investments. If access to the capital markets is adversely affected by any widespread illness or disease, we may need to consider alternative sources of funding for our operations and for working capital, any of which may not be available and may increase our cost of capital. An extended period of disruption to the economy, our workforce, supply chains or capital markets due to the widespread outbreak of an illness or disease could materially impact our business, financial condition, results of operations, cash flows and credit metrics.

Acts of war, terrorist attacks and other catastrophic events may have a material adverse effect on our business, financial condition, results of operations and cash flows.

Acts of war, terrorist attacks and other catastrophic events may negatively affect our business, financial condition and cash flows in unpredictable ways, such as increased security measures and disruptions of markets and supply chains. Energy related assets, including, for example, our transmission facilities and DTE Electric’s, Consumers Energy’s and IP&L’s generation and distribution facilities that we interconnect with, may be at risk of acts of war, terrorist attacks and other catastrophic events. Such events or threats may have a material effect on the economy in general and could result in a decline in energy consumption, which may have a material adverse effect on our business, financial condition, results of operations and cash flows.

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Advances in technology may negatively impact our business, financial condition, results of operations and cash flows.

Research and development efforts continue to seek improvements to existing or new alternative technologies to produce, store and distribute power, including fuel cells, microturbines, distributed generation and battery storage. It is possible that adoption of such alternative technologies could be significant enough to cause a reduction in the demand for electricity from the traditional bulk electric system or could make portions of our transmission systems obsolete before the end of their useful lives. Such advances in alternative technologies could decrease the need for capital investments in our transmission systems over time or increase cost, and as a result could have an adverse effect on our business, financial condition, results of operations and cash flows.

Risks Relating to Our Corporate and Financial Structure

ITC Holdings is a holding company with no operations, and unless we receive dividends or other payments from our subsidiaries, we may be unable to fulfill our cash obligations.

As a holding company with no business operations, ITC Holdings’ material assets consist primarily of the stock and membership interests in our subsidiaries. Our primary sources of cash to meet our obligations are dividends and other payments received by us from time to time from our subsidiaries, the proceeds raised from the sale of our securities and borrowings under our various credit agreements. Each of our subsidiaries, however, is legally distinct from us and has no obligation, contingent or otherwise, to make funds available to us. The ability of each of our Regulated Operating Subsidiaries and our other subsidiaries to pay dividends and make other payments to us is subject to, among other things, the availability of funds, after taking into account capital expenditure requirements, the terms of its indebtedness, applicable state laws and regulations of the FERC and the FPA. Our Regulated Operating Subsidiaries target a FERC-approved capital structure of 60% equity and 40% debt that may limit the ability of our Regulated Operating Subsidiaries to use net assets for the payment of dividends to ITC Holdings. In addition, ITC Holdings’ right to receive any assets of any subsidiary, and therefore the right of its creditors to participate in those assets, will be effectively subordinated to the claims of that subsidiary’s creditors. If ITC Holdings does not receive cash or other assets from our subsidiaries, it may be unable to pay principal and interest on its indebtedness.

We have a considerable amount of debt and our reliance on debt financing may limit our ability to fulfill our debt obligations and/or to obtain additional financing.

We have a considerable amount of debt and our consolidated indebtedness may include various debt securities and borrowings, which utilize indentures, revolving and term loan credit agreements and commercial paper that we rely on as sources of capital and liquidity. Our capital structure can have several important consequences, including, but not limited to, the following:

•If future cash flows are insufficient, we may not be able to make principal or interest payments on our debt obligations, which could result in the occurrence of an event of default under one or more of those debt instruments.

•We may need to increase our indebtedness in order to make the capital expenditures and other expenses or investments planned by us.

•Our indebtedness has the general effect of reducing our flexibility to react to changing business and economic conditions insofar as they affect our financial condition. A substantial portion of the dividends and payments in lieu of taxes we receive from our subsidiaries will be dedicated to the payment of interest on our indebtedness, thereby, reducing our available cash.

•In the event that we are liquidated, the creditors of our subsidiaries will be entitled to payment in full of the subsidiaries’ indebtedness prior to making any payments to ITC Holdings for the payment of its indebtedness.

•We currently have debt instruments outstanding with short-term maturities or relatively short remaining maturities. Our ability to secure additional financing prior to or after these facilities mature, if needed, may be substantially restricted by the existing level of our indebtedness and the restrictions contained in our debt instruments. Additionally, the interest rates at which we might secure additional financings may be

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higher than our currently outstanding debt instruments or higher than forecasted at any point in time, which could adversely affect our business, financial condition, results of operations and cash flows.

•Market conditions could affect our access to capital markets, restrict our ability to secure financing to make the capital expenditures and investments and pay other expenses planned by us which could adversely affect our business, financial condition, results of operations and cash flows.

We may incur substantial additional indebtedness in the future. The incurrence of additional indebtedness would increase the leverage-related risks described above.

Adverse changes in our credit ratings may negatively affect us.

Our ability to access capital markets is important to our ability to operate our business. Increased scrutiny of the energy industry and the impact of regulation, as well as changes in our financial performance and unfavorable conditions in the capital markets could result in credit agencies reexamining and downgrading our credit ratings. In addition, because we are a subsidiary of Fortis, a downgrade in Fortis’ credit rating could cause our credit rating to be downgraded as well, even if our creditworthiness has not otherwise deteriorated. A downgrade in our credit ratings could restrict or discontinue our ability to access capital markets at attractive rates and increase our borrowing costs. A rating downgrade could also increase the interest we pay on our debt instruments.

Certain provisions in our debt instruments limit our financial and operating flexibility.

Our debt instruments on a consolidated basis, which may include senior notes, secured notes, first mortgage bonds, revolving and term loan credit agreements and commercial paper, contain numerous financial and operating covenants that place significant restrictions on, among other things, our ability to:

•incur additional indebtedness;

•engage in sale and lease-back transactions;

•create liens or other encumbrances;

•enter into mergers, consolidations, liquidations or dissolutions, or sell or otherwise dispose of all or substantially all of our assets;

•create and acquire subsidiaries; and

•pay dividends or make distributions on our stock or on the stock or member capital of our subsidiaries.

In addition, the covenants require us to meet certain financial ratios, such as maintaining certain debt to capitalization ratios and certain funds from operations to debt levels. Our ability to comply with these and other requirements and restrictions may be affected by changes in economic or business conditions, results of operations or other events beyond our control. A failure to comply with the obligations contained in any of our debt instruments could result in acceleration of related debt and the acceleration of debt under other instruments evidencing indebtedness that may contain cross-acceleration or cross-default provisions.

ITEM 1B. UNRESOLVED STAFF COMMENTS.

None.

ITEM 1C. CYBERSECURITY.

In response to cybersecurity threats to our business, which include threats to our operations, critical infrastructure assets, information systems and data, we have developed a comprehensive cybersecurity risk management program.

Governance

Primary responsibility for assessing, monitoring, and managing our cybersecurity risks is overseen by our Chief Information Officer (CIO). Our CIO has maintained certification as a Certified Information Security Manager since 2006 and brings extensive experience in information technology and in-depth knowledge in developing and executing our cybersecurity strategies. At the direction of the Board of Directors, our management has developed a cybersecurity policy which includes the establishment of, and ongoing monitoring by, a cybersecurity steering committee led by the CIO and comprised of executives from key departments,

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including legal, finance, accounting, operations, engineering and human resources. The committee meets quarterly and on an as-needed basis and is charged with overseeing and assisting the information technology department in directing cybersecurity activities to protect the Company, including its operations, systems and related information. It also oversees and reviews policies, procedures, and internal controls for cybersecurity as well as the cybersecurity risk management program.

Given the importance to our business and the heightened risk, the Board of Directors provides oversight of management’s response to cybersecurity risks. Management, including our CIO, provides the Board of Directors periodic updates on cybersecurity, including updates on cyber goals, cybersecurity risks, and related risk mitigation strategies. As part of our enterprise risk management process, an annual risk assessment is completed by a cross-functional group of management led by our finance department, and includes members of our information technology department for the cybersecurity assessment section. The results of the risk assessment, as well as mitigation strategies, are discussed with the Board of Directors.

Risk Management and Strategy

In addition to the enterprise risk management process, we utilize an additional cybersecurity risk management program that assesses the risks and protections of several key assets within the organization. As a result of these assessments and as the threat landscape becomes increasingly sophisticated, we continue to evolve our defensive strategy by deploying new technology, continuing education of our user community, and advancing our protections against ongoing cybersecurity risks and threats. Protecting our infrastructure assets, along with our information systems and data, against outside threats is of vital importance and we plan to continue to invest in new technology, including investments within our five-year plan for capital expenditures for the years 2026 to 2030, to address these risks. We leverage threat intelligence and external industry practices for continuous improvement and refinement of our cybersecurity program.

Given the regulatory framework under which we operate, we follow a cybersecurity incident response plan that is tested annually in compliance with NERC’s critical infrastructure protection standards and includes external disclosure procedures. This plan identifies the members of our cybersecurity incident response team and the criteria to identify, classify and respond to a cybersecurity incident. Cybersecurity incidents are communicated to internal stakeholders, such as management and the Board of Directors, and external stakeholders based on severity of the incident in accordance with the cybersecurity response plan.

Our CIO oversees a team of cybersecurity professionals in the cyber security operations center with certifications in cybersecurity engineering and cybersecurity operational areas. We also utilize internal audits to periodically assess the effectiveness of our cybersecurity processes and external parties to periodically conduct threat and vulnerability assessments. We continue to invest in training for all employees, including training for our cybersecurity professionals on the specific technologies utilized within the company and development of these individuals to keep their knowledge current. Additionally, we have a vendor risk management program to review and assess cybersecurity risks related to utilizing information technology vendor products and services for new and existing vendors that is subject to ongoing monitoring.

Refer to the discussion of risks and uncertainties associated with cyber-attacks or incidents in this report under “Item 1A. Risk Factors.” We are not aware of any cybersecurity incidents that have materially affected, or are reasonably likely to materially affect the Company, our business strategy, results of operations or financial condition.

ITEM 2. PROPERTIES.

Our Regulated Operating Subsidiaries’ transmission facilities are located in Michigan, Iowa, Minnesota, Illinois, Missouri, Kansas, Oklahoma and Wisconsin. Our Regulated Operating Subsidiaries have agreements with other utilities for the joint ownership of specific substations, transmission lines and other transmission assets. See Note 15 to the consolidated financial statements for more information on the jointly owned assets.

Our Regulated Operating Subsidiaries own the assets of transmission systems and related assets, including:

•approximately 16,000 circuit miles of overhead and underground transmission lines rated at voltages of 34.5 kV to 345 kV, along with related transmission towers and poles;

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•station assets, such as transformers and circuit breakers, at 714 stations and substations which either interconnect our Regulated Operating Subsidiaries’ transmission facilities or connect our Regulated Operating Subsidiaries’ facilities with generation or distribution facilities owned by others;

•other transmission equipment necessary to safely operate the system (e.g., monitoring and metering equipment);

•warehouses and related equipment; and

•associated land held in fee, rights-of-way and easements.

ITCTransmission owns a corporate headquarters facility and operations control room in Novi, Michigan and a facility in Ann Arbor, Michigan that includes a back-up operations control room, along with associated furniture, fixtures and office equipment for these facilities. ITC Midwest owns an office building in Cedar Rapids, Iowa, along with associated furniture, fixtures and office equipment.

METC does not own the majority of the land on which its assets are located, but under the provisions of the Easement Agreement, METC has an easement to use the land, rights-of-way, leases and licenses in the land on which its transmission lines are located that are held or controlled by Consumers Energy. See “Item 1. Business - Operating Contracts - METC - Amended and Restated Easement Agreement.”

Our Regulated Operating Subsidiaries have issued First Mortgage Bonds and Senior Secured Notes. Under the terms of these instruments, the respective bondholders and noteholders have the benefit of a first mortgage lien on substantially all of the assets of the corresponding debt issuer. See Note 9 to the consolidated financial statements for more information on the outstanding debt of our Regulated Operating Subsidiaries.

The assets of our Regulated Operating Subsidiaries are suitable for electric transmission and adequate for the electricity demand in our service territory. We prioritize capital spending based in part on meeting reliability standards within the industry. This includes replacing and upgrading existing assets as needed.

ITEM 3. LEGAL PROCEEDINGS.

We are involved in certain legal proceedings before various courts, governmental agencies and mediation panels concerning matters arising in the ordinary course of business. These may include proceedings such as contract disputes, eminent domain and vegetation management activities, regulatory matters and pending judicial matters. We cannot predict the final disposition of such proceedings. We regularly review legal matters and record provisions for claims that are considered reasonably estimable and probable of loss.

See Note 17 to the consolidated financial statements for a description of certain pending legal proceedings, which description is incorporated herein by reference.

ITEM 4. MINE SAFETY DISCLOSURES.

Not applicable.

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PART II


ITEM 5.			MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

ITC Holdings is a wholly-owned subsidiary of ITC Investment Holdings and ITC Holdings’ common stock is not publicly traded.

ITC Holdings paid dividends of $149 million and $343 million to our parent, ITC Investment Holdings, during the years ended December 31, 2025 and 2024, respectively. The timing and amount of future dividends is subject to an approved dividend declaration from our Board of Directors, and is dependent upon cash flows, capital requirements, legislative and regulatory developments, and financial condition of ITC Holdings, among other factors deemed relevant. On February 2, 2026, our Board of Directors approved a $72 million dividend to ITC Investment Holdings that is expected to be paid on February 27, 2026.

ITEM 6. [Reserved]


ITEM 7.			MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

Safe Harbor Statement Under The Private Securities Litigation Reform Act of 1995

Our reports, filings and other public announcements contain certain statements that describe our management’s beliefs concerning future business conditions, plans and prospects, forecasted capital expenditures, dividend payments, growth opportunities, the outlook for our business and the electric transmission industry, and expectations with respect to various legal and regulatory proceedings based upon information available at the time such statements are made. All statements, other than statements of historical fact, included in this report are “forward-looking” statements within the meaning of the Private Securities Litigation Reform Act of 1995. Wherever possible, we have identified these forward-looking statements by words such as “will,” “may,” “anticipates,” “believes,” “intends,” “estimates,” “expects,” “forecasted,” “projects,” “likely,” “could,” “might,” “target,” “would,” “plan,” “potential,” “continue,” “should,” “predict,” “seeks,” and the negative of these terms, and similar phrases. These forward-looking statements are based upon assumptions our management believes are reasonable. Such forward-looking statements are based on estimates and assumptions and are subject to significant risks and uncertainties which could cause our actual results, performance and achievements to differ materially from those expressed in, or implied by, these statements, including, among others, the risks and uncertainties listed in this report under “Item 1A. Risk Factors” and in our other reports filed with the SEC from time to time.

Forward-looking statements speak only as of the date made and can be affected by assumptions we might make or by known or unknown risks and uncertainties. Many factors mentioned in our discussion in this report will be important in determining future results. Consequently, we cannot assure you that our expectations or forecasts expressed in such forward-looking statements will be achieved. Except as required by law, we undertake no obligation to publicly update any of our forward-looking or other statements, whether as a result of new information, future events or otherwise.

Statement on Prior Period Comparisons

This section of this Form 10-K generally discusses the financial condition, changes in financial condition and results of operations for the years ended December 31, 2025 and 2024 and provides year-to-year comparisons between the years ended December 31, 2025 and 2024. Discussions of such information for the year ended December 31, 2023 and year-to-year comparisons between the years ended December 31, 2024 and 2023 that are not included in this Form 10-K can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7. of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2024.

Overview

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continue to make investments in a modernized grid to maintain reliability and accommodate future demands as lifestyles and the economy become increasingly dependent on electricity.

Our Regulated Operating Subsidiaries earn revenues for the use of their electric transmission systems by their customers, which include investor-owned utilities, municipalities, cooperatives, power marketers and alternative energy suppliers. As independent transmission companies, our Regulated Operating Subsidiaries are subject to rate regulation only by the FERC, and our cost-based rates are discussed below under “— Cost-Based Formula Rates with True-Up Mechanism” as well as in Note 6 to the consolidated financial statements.

Significant matters that influenced our financial condition, results of operations and cash flows for the year ended December 31, 2025 or that may affect future results include:

•Our capital expenditures of $1.3 billion at our Regulated Operating Subsidiaries during the year ended December 31, 2025, as described below under “— Capital Investment and Operating Results Trends;”

•Debt activity, including derivatives, as described in Note 9 to the consolidated financial statements;

•The October 2024 Order and appeal proceedings as described in Note 17 to the consolidated financial statements; and

•NOPRs previously issued by the FERC proposing changes to transmission incentives policy, as described in Note 6 to the consolidated financial statements.

Recent Developments

Iowa Courts’ Rulings on Right of First Refusal and First Tranche of MISO’s LRTP

In 2020, the State of Iowa enacted a state law that granted incumbent Iowa electric TOs, including ITC Midwest, a ROFR to construct, own and maintain certain electric transmission assets in the state. On October 14, 2020, LS Power Midcontinent, LLC and Southwest Transmission, LLC sued the IUC and several individual defendants, seeking a judgment that the ROFR provisions violated the Iowa Constitution and requesting a temporary injunction of the ROFR until the case was resolved. The case was dismissed in district court based on the plaintiffs’ lack of standing in the case and the court of appeals later affirmed the district court’s ruling.

Following appeal, on March 24, 2023, the Iowa Supreme Court issued an opinion that the plaintiffs have standing to challenge the ROFR provision, thereby vacating the decision of the court of appeals, reversing the district court’s judgment and remanding the case to the Iowa District Court for Polk County to determine the merits regarding the constitutionality of the ROFR statute. As part of this opinion, the Iowa Supreme Court also issued a temporary injunction staying the enforcement of the ROFR. However, ITC Midwest had already exercised its right to construct certain electric transmission projects approved and awarded by MISO, as the decision for assignment of the first tranche of LRTP projects in Iowa was finalized by MISO on July 25, 2022. MISO is the only entity charged with determining what projects are to be competitively bid pursuant to its tariff.

On December 4, 2023, the Iowa District Court for Polk County issued a decision finding that the manner in which Iowa’s ROFR statute was passed is unconstitutional. The court did not make any determination on the merits of the ROFR itself. The district court issued a permanent injunction preventing ITC Midwest and others from taking further action to construct the first tranche of Iowa’s LRTP projects in reliance on the ROFR. However, the district court ordered that the injunction does not prohibit ITC Midwest from seeking approval from the IUC to construct projects included in the first tranche of LRTP, so long as the approval is unrelated to a claim under the ROFR statute. ITC Midwest filed for reconsideration of the district court’s decision with respect

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to the scope of the injunction. On March 19, 2024, the district court issued an order denying all motions for reconsideration of its decision. ITC Midwest appealed this order on April 17, 2024.

On July 5, 2024, the Iowa Supreme Court granted a motion filed by ITC Midwest requesting a stay of the injunction issued by the district court while the district court’s orders are appealed. LS Power Midcontinent, LLC and Southwest Transmission, LLC requested quorum review of the stay of the injunction. On August 7, 2024, the Iowa Supreme Court vacated the stay and reinstated the injunction. On May 30, 2025, the Iowa Supreme Court issued an order denying ITC Midwest’s appeal and affirming the permanent injunction.

On May 28, 2024, MISO confirmed commencement of a variance analysis process on the grounds that there was an inability to construct a portion of the first tranche of MISO’s LRTP projects in Iowa due to the injunction imposed by the district court order. On August 29, 2024, MISO publicly posted the conclusion of the variance analysis whereby its Competitive Transmission Executive Committee, which maintains authority to oversee and implement variance analyses pursuant to the MISO tariff, reaffirmed MISO’s assignment of ownership and construction responsibility for the portion of the first tranche of MISO’s LRTP projects in Iowa to ITC Midwest and MidAmerican Energy Company. The results of MISO’s variance analysis process allow ITC Midwest to move forward with development of its portion of the first tranche of MISO’s LRTP projects in Iowa. On June 27, 2025, ITC Midwest filed a supplemental brief in response to a June 5, 2025 letter from the IUC requesting ITC Midwest to identify the basis upon which the IUC should proceed consistent with the Iowa Supreme Court’s May 30, 2025 decision. On July 22, 2025, in a hearing related to one of the projects assigned to ITC Midwest in Iowa in the first tranche of MISO’s LRTP, the IUC recognized MISO’s variance analysis as the proper remedy to the injunction which allows the continued development of these projects in Iowa.

Cost-Based Formula Rates with True-Up Mechanism

Our Regulated Operating Subsidiaries calculate their respective revenue requirements using a cost-based formula based on company specific financial information. The calculation of projected revenue requirement for a future period, generally a calendar year, is used to establish the transmission rate used for billing purposes. The calculation of actual revenue requirements for a historic period is used to calculate the amount of revenues recognized in that period and determine the over- or under-collection for that period. See “Cost-Based Formula Rates with True-Up Mechanism” in Note 6 to the consolidated financial statements for further discussion of our Formula Rates and see “Rate of Return on Equity Complaints” in Note 17 to the consolidated financial statements for detail on MISO ROE Complaints.

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Illustrative Example of Formula Rate Setting

The Formula Rate setting example shown below is for illustrative purposes only and is not based on our actual financial data.


Line	Item	Instructions	Amount
1	Rate base (a)		$	1,000,000
2	Multiply by 13-month weighted average cost of capital (b)		8.44		%
3	Authorized return on rate base	(Line 1 x Line 2)	$	84,400
4	Recoverable operating expenses (including depreciation and amortization)		$	150,000
5	Income taxes (c)		37,500
6	Gross revenue requirement	(Line 3 + Line 4 + Line 5)	$	271,900

____________________________

(a)Consists primarily of in-service property, plant and equipment, net of accumulated depreciation.

(b)The weighted average cost of capital for purposes of this illustration is calculated below. The cost of capital for debt is included at a flat interest rate for purposes of this illustration and is not based on our actual cost of capital. The cost of capital rate for equity represents the current maximum allowed MISO ROE per the October 2024 Order. See Note 17 to the consolidated financial statements for detail on ROE matters.


			Weighted
			Average
	Percentage of		Cost of
	Total Capitalization	Cost of Capital	Capital
Debt	40.00%	5.00% =	2.00	%
Equity	60.00%	10.73% =	6.44	%
	100.00%		8.44	%

(c)Represents an approximation of the federal and state income tax expense for purposes of this illustration and is not based on our actual tax expense.

Revenue Accruals and Deferrals — Effects of Monthly Network Peak Loads

For our MISO Regulated Operating Subsidiaries, monthly network peak loads are used for billing network revenues, which currently is the largest component of our operating revenues. One of the primary factors that impacts the revenue accruals and deferrals at our MISO Regulated Operating Subsidiaries is actual monthly network peak loads experienced as compared to those forecasted in establishing the annual network transmission rate. Under their cost-based Formula Rates that contain a true-up mechanism, our MISO Regulated Operating Subsidiaries accrue or defer revenues to the extent that their actual revenue requirement for the reporting period is higher or lower, respectively, than the amounts billed relating to that reporting period. These revenue accruals and deferrals are recorded to the consolidated statements of financial position within regulatory assets or regulatory liabilities, respectively. See Note 6 to the consolidated financial statements for additional information on our Formula Rates. Although monthly network peak loads do not impact operating revenues recognized, network load affects the timing of our cash flows from transmission service. The monthly network peak load of our MISO Regulated Operating Subsidiaries is generally impacted by weather, economic conditions and other significant factors and is seasonally shaped with higher load in the summer months when cooling demand is higher. We are unable to predict the possible future impacts of weather, economic conditions and other factors on monthly network peak loads at our MISO Regulated Operating Subsidiaries.

Capital Investment and Operating Results Trends

We expect a long-term upward trend in rate base resulting from our anticipated capital investment, in excess of depreciation and any acquisition premiums, from our Regulated Operating Subsidiaries’ long-term capital investment programs to improve reliability, increase system capacity and upgrade the transmission network to support new generating resources. Investments in property, plant and equipment, when placed in-service upon completion of a capital project, are added to the rate base of our Regulated Operating Subsidiaries. We expect increases in rate base to result in a corresponding long-term upward trend in revenues and earnings. Our revenues and earnings may be impacted by future increases or decreases to our rates for ROE incentive adders and base ROE. As of December 31, 2025, we estimate that each 10 basis point change in the

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authorized ROE would impact annual consolidated net income by approximately $7 million. See Note 6 and Note 17 to the consolidated financial statements for additional information related to matters that have impacted base ROE and may impact future rates.

Our Regulated Operating Subsidiaries incur significant costs to invest in their transmission systems and maintain the assets on their systems. While we have been impacted by increases in inflation and supply chain disruptions, these challenges have not had a material impact on our current or forecasted capital expenditures. We work closely with our suppliers to manage costs and deliveries of required materials and supplies and attempt to ensure that our asset and inventory purchases adequately support our construction and maintenance activities. In response to these challenges, we have increased levels of certain materials and supplies inventories over time to help reduce risks related to global supply chain constraints. We continue to monitor and evaluate the potential impacts of these macroeconomic trends on our forecasted capital expenditures and maintenance activities. Recently announced changes and proposed changes to the U.S. global trade policy, along with potential international retaliatory measures, have resulted in volatility in global markets and uncertainty around short- and long-term economic impacts in the United States, including concerns over tariffs and their potential impacts on the cost of goods, inflation, recession and slowing growth. As such, we continue to monitor and evaluate the potential impacts of these changes and measures, including the imposition of tariffs and ongoing legal challenges to such tariffs, on our business and operations. It is not currently possible to predict the impact of any changes or proposed changes to the U.S. global trade policy, or any international retaliatory measures, on our forecasted capital expenditures for the years 2026 through 2030 or our long-term financial condition, results of operations and cash flows. However, we did not experience a significant impact to our financial condition, results of operations and cash flows during the year ended December 31, 2025 and we do not currently expect a significant financial impact in 2026.

We are also monitoring and evaluating the potential impact of various executive orders issued by the U.S. government on our business, including potential impacts to our financial condition, results of operations and cash flows. On October 1, 2025, FERC issued a final rule to comply with the executive order entitled “Zero-Based Regulatory Budgeting to Unleash American Energy,” which establishes a sunset date for certain regulations. We do not expect a significant impact from the final rule.

Our Regulated Operating Subsidiaries strive for high reliability of their systems and improvement in system accessibility for all generation resources. The FERC requires compliance with certain reliability standards and may take enforcement actions against violators, including the imposition of substantial fines. NERC is responsible for developing and enforcing these mandatory reliability standards. We continually assess our transmission systems against standards established by NERC, as well as the standards of applicable regional entities under NERC that have been delegated certain authority for the purpose of proposing and enforcing reliability standards. We believe that we meet the applicable standards in all material respects, although further investment in our transmission systems and an increase in maintenance activities will likely be needed to maintain compliance, improve reliability and address any new standards that may be promulgated.

We also assess our transmission systems against our own planning criteria that are filed annually with the FERC. Based on our planning studies, we see needs to make capital investments to: (1) maintain and replace our current transmission infrastructure to enhance system reliability and accommodate load growth; (2) expand access to electricity markets to reduce the overall cost of delivered energy to customers and provide access to competitive markets for economic development; (3) interconnect new generation resources; and (4) upgrade physical and technological grid security to protect critical infrastructure.

In addition to future investments identified through our planning studies, MISO continues to identify capital investment needs through its LRTP initiative. The objective of this initiative is to ensure grid reliability while integrating the different operating characteristics of new generation resources and increase resiliency of the grid during severe weather events. The MISO LRTP will result in additional capital investments across MISO’s Midwest subregion, including investments for our MISO Regulated Operating Subsidiaries. On December 12, 2024, MISO’s board of directors approved a portfolio of the second tranche of 24 LRTP projects (“Tranche 2.1”) with estimated total associated transmission costs of approximately $22 billion. Based on the MISO portfolio of Tranche 2.1 projects, we expect a range of $3.7 billion to $4.2 billion of additional capital investments for our MISO Regulated Operating Subsidiaries. At this time, this range includes the estimate of future capital investments for projects from the Tranche 2.1 portfolio that are not subject to a competitive bidding process. We currently anticipate that the majority of our investments for the Tranche 2.1 portfolio will occur beyond our five-

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year plan for forecasted capital expenditures for the years 2026 through 2030. On July 30, 2025, certain state regulatory commissions in the MISO region filed a complaint at the FERC challenging the manner in which MISO developed the Tranche 2.1 portfolio and the designation of projects in the portfolio as multi-value projects. We are monitoring developments in the complaint proceedings; however, we are unable to determine the possible impacts to capital expenditures for Tranche 2.1 projects at this time.

The following table shows our actual and expected capital expenditures at our Regulated Operating Subsidiaries:

Actual Capital

Forecasted

Expenditures for the

Capital

Year Ended

Expenditures

(In millions of USD)

December 31, 2025

2026 — 2030

Expenditures for property, plant and equipment (a)

1,315

7,291

____________________________

(a)Amounts represent the cash payments to acquire or construct property, plant and equipment, as presented in the consolidated statements of cash flows. These amounts exclude non-cash additions to property, plant and equipment for the AFUDC equity as well as accrued liabilities for construction, labor and materials that have not yet been paid.

Our five-year forecasted capital expenditure plan for the years 2026 through 2030 results in a forecasted 25% increase in our plan for capital expenditures compared to the previous plan that was developed for the years 2025 through 2029. The increase is primarily driven by the addition to the plan of expenditures for the first tranche of MISO’s LRTP projects, the incorporation of capital expenditures for projects not subject to a competitive bidding process in Tranche 2.1 of MISO’s LRTP, capital expenditures not included in the previous plan for customer and generator interconnection projects and other base capital expenditures considered necessary to our business.

Our long-term growth plan includes ongoing investments in our current regulated transmission systems and the identification of incremental strategic projects primarily located in and around our service territories. In addition, evolving technologies such as data centers, with increasing energy demand and load capacity requirements, will require electric transmission systems to adapt to future demands at a scale and pace beyond the historical trends of development. Excluding other factors that may impact network transmission rates, load increases driven by economic development and new customer interconnections are expected to put downward pressure on future rates.

Our capital expenditure forecast is subject to continuing review and modification. Investments in property, plant and equipment could be lower than expected due to a variety of factors, as discussed in “Item 1A. Risk Factors.”

Significant Components of Results of Operations

Revenues

We derive nearly all of our revenues from providing transmission, scheduling, control and dispatch services and other related services over our Regulated Operating Subsidiaries’ transmission systems to DTE Electric, Consumers Energy, IP&L and other entities, such as alternative energy suppliers, power marketers and other wholesale customers that provide electricity to end-use consumers, as well as from transaction-based capacity reservations on our transmission systems. MISO and SPP are responsible for billing and collecting the majority of transmission service revenues. As the billing agents for our MISO Regulated Operating Subsidiaries and ITC Great Plains, MISO and SPP collect fees for the use of our transmission systems, invoicing DTE Electric, Consumers Energy, IP&L and other customers on a monthly basis.

Network Revenues are generated from network customers for their use of our electric transmission systems and are based on the actual revenue requirements as a result of our accounting under our cost-based Formula Rates that contain a true-up mechanism. See Note 6 to the consolidated financial statements for a discussion of revenue recognition relating to network revenues.

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

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

Point-to-Point Revenues consist of revenues generated from a type of transmission service for which the customer pays for transmission capacity reserved along a specified path between two points on an hourly, daily, weekly or monthly basis. Point-to-point revenues also include other components pursuant to schedules under the MISO and SPP transmission tariffs. Point-to-point revenues are treated as a revenue credit to network or regional customers and are a reduction to gross revenue requirement when calculating net revenue requirement under our cost-based Formula Rates.

Scheduling, Control and Dispatch Revenues are allocated to our MISO Regulated Operating Subsidiaries by MISO as compensation for the services performed in operating the transmission system. Such services include monitoring of reliability data, current and next day analysis, implementation of emergency procedures and outage coordination and switching.

Other Revenues consist of rental revenues, easement revenues, revenues relating to utilization of jointly owned assets under our transmission ownership and operating agreements and amounts from providing ancillary services to customers. The majority of other revenues are treated as a revenue credit and taken as a reduction to gross revenue requirement when calculating net revenue requirement under our cost-based Formula Rates.

Operating Expenses

Operation and Maintenance Expenses consist primarily of the costs for contractors that operate and maintain our transmission systems as well as our personnel involved in operation and maintenance activities.

Operation expenses include activities related to control area operations, which involve balancing loads and generation and transmission system operations activities, including monitoring the status of our transmission lines and stations. Rental expenses relating to land easements, including METC’s Easement Agreement, are also recorded within operation expenses.

Maintenance expenses include preventive or planned activities, such as vegetation management, tower painting and equipment inspections, as well as reactive maintenance for equipment failures.

General and Administrative Expenses consist primarily of costs for personnel in our legal, information technology, finance, regulatory, human resources, community relations and communication and other support functions, general office expenses and fees for professional services. Professional services are principally composed of outside legal, consulting, audit and information technology services.

Depreciation and Amortization Expenses consist primarily of depreciation of property, plant and equipment using the straight-line method of accounting. Additionally, this consists of amortization of various regulatory assets.

Taxes Other than Income Taxes consist primarily of property taxes and payroll taxes.

Other Items of Income or Expense

Interest Expense consists primarily of interest on debt at ITC Holdings and our Regulated Operating Subsidiaries. Additionally, the amortization of debt financing expenses are recorded to interest expense. An allowance for borrowed funds used during construction is included in property, plant and equipment accounts and treated as a reduction to interest expense. The amortization of gains and losses on settled and terminated derivative financial instruments is recorded to interest expense.

Allowance for Equity Funds Used During Construction (“AFUDC equity”) is recorded as an item of other income and is included in property, plant and equipment accounts. The allowance represents a ROE at our Regulated Operating Subsidiaries used for construction purposes in accordance with the FERC regulations.

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The capitalization rate applied to the construction work in progress balance is based on the proportion of equity to total capital (which currently includes equity and long-term debt) and the authorized ROE for our Regulated Operating Subsidiaries.

Income Tax Provision

Income tax provision consists of current and deferred federal and state income taxes.

Results of Operations


	Year Ended						Percentage
	December 31,				Increase		Increase
(In millions of USD)	2025		2024		(Decrease)		(Decrease)
OPERATING REVENUES
Transmission and other services	$	1,775	$	1,613	$	162	10	%
Formula Rate true-up	11		12		(1)		(8)	%
Total operating revenues	1,786		1,625		161		10	%
OPERATING EXPENSES
Operation and maintenance	116		111		5		5	%
General and administrative	153		121		32		26	%
Depreciation and amortization	349		326		23		7	%
Taxes other than income taxes	181		154		27		18	%
Other operating expenses (income), net	—		(1)		1		100	%
Total operating expenses	799		711		88		12	%
OPERATING INCOME	987		914		73		8	%
OTHER EXPENSES (INCOME)
Interest expense, net	364		348		16		5	%
Allowance for equity funds used during construction	(44)		(44)		—		—	%
Other expenses (income), net	(11)		(22)		11		50	%
Total other expenses (income)	309		282		27		10	%
INCOME BEFORE INCOME TAXES	678		632		46		7	%
INCOME TAX PROVISION	159		148		11		7	%
NET INCOME	$	519	$	484	$	35	7	%

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Operating Revenues

The following table sets forth the components of and changes in operating revenues for the years ended December 31, 2025 and 2024, which included revenue accruals and deferrals as described in Note 6 to the consolidated financial statements:


											Percentage
	2025				2024				Increase		Increase
(In millions of USD)	Amount		Percentage		Amount		Percentage		(Decrease)		(Decrease)
Network revenues (a)	$	1,273	71	%	$	1,175	72	%	$	98	8	%
Regional cost sharing revenues (a)	438		24	%	402		25	%	36		9	%
Point-to-point	29		2	%	21		1	%	8		38	%
Scheduling, control and dispatch (a)	16		1	%	18		1	%	(2)		(11)	%
October 2024 Order refund accrual	—		—	%	(21)		(1)	%	21		100	%
Other	30		2	%	30		2	%	—		—	%
Total	$	1,786	100	%	$	1,625	100	%	$	161	10	%

____________________________

(a)Includes a portion of Formula Rate true-up revenue.

Operating revenues for the year ended December 31, 2025 increased compared to the year ended December 31, 2024 primarily due to higher rate base associated with higher balances of property, plant and equipment and resulting return. Other contributors included increased recoverable operating expenses and no recognition of the liability for the refund related to the October 2024 Order in the year ended December 31, 2025.

Operating Expenses

General and administrative

General and administrative expense increased during the year ended December 31, 2025 compared to the year ended December 31, 2024 primarily due to an increase in share based compensation. Other factors included increased salaries caused by a higher employee count.

Taxes other than income taxes

Taxes other than income taxes increased during the year ended December 31, 2025 compared to the year ended December 31, 2024 primarily due to an increase in property taxes as a result of expiring state tax exemptions in Kansas and additional plant in service.

Other Expenses (Income)

Other expenses (income), net

Other expenses (income), net decreased for the year ended December 31, 2025 compared to the year ended December 31, 2024 primarily due to a decrease in interest income.

Liquidity and Capital Resources

We expect to maintain our approach of funding our future capital requirements with cash provided by operations at our Regulated Operating Subsidiaries, future issuances under our commercial paper program and amounts available under our revolving credit agreement (the terms of which are described in Note 9 to the consolidated financial statements). In addition, we may secure fixed debt funding in the capital markets, although we can provide no assurance that we will be able to obtain financing on favorable terms or at all. As market conditions warrant, we may also from time to time repurchase debt securities issued by us in the open market, in privately negotiated transactions, by tender offer or otherwise. We expect that our capital requirements will arise principally from our need to:

•Fund capital expenditures (including purchase obligations as described in Note 17 to the consolidated financial statements) at our Regulated Operating Subsidiaries. Our plans with regard to property, plant and equipment investments are described in detail above under “— Capital Investment and Operating Results Trends.”

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•Fund our debt service requirements, including principal repayments and periodic interest payments, which are further described below.

•Fund working capital requirements.

In addition to the expected capital requirements above, any adverse determinations or settlements relating to the regulatory matters or contingencies described in Notes 6 and 17 to the consolidated financial statements would result in additional capital requirements.

We believe that we have sufficient capital resources to meet our currently anticipated short-term (within twelve months) needs. However, we rely on both internal and external sources of liquidity to provide working capital and fund capital investments. An extended period of economic disruption could impact our ability to access the capital markets requiring us to seek alternative forms of financing which could negatively impact our liquidity and capital resources. Additionally, we will continue to monitor and assess interest rates and the lending environment to inform our funding strategy, including the utilization of various types of debt instruments.

ITC Holdings’ sources of cash are dividends and other payments received by us from our Regulated Operating Subsidiaries and any of our other subsidiaries as well as the proceeds raised from the sale of our debt securities. Each of our Regulated Operating Subsidiaries, while wholly-owned by ITC Holdings, is legally distinct from ITC Holdings and has no obligation, contingent or otherwise, to make funds available to ITC Holdings.

To address our short-term (within twelve months) cash requirements, we expect to utilize cash provided by operations at our Regulated Operating Subsidiaries, future issuances under our commercial paper program, amounts available under our revolving credit agreement and long-term debt financing, as needed. As of December 31, 2025, we had consolidated indebtedness under our revolving credit agreement of $589 million, with unused capacity of $411 million. Additionally, ITC Holdings had $237 million of commercial paper issued and outstanding as of December 31, 2025, with the ability to issue an additional $163 million under the commercial paper program. In 2025, we paid $33 million of interest and commitment fees under our revolving credit agreement and commercial paper program. See Note 9 to the consolidated financial statements for a detailed discussion of the commercial paper program and our revolving credit agreement.

To address our future long-term capital requirements, we expect that we will need to obtain additional long-term debt financing. As of December 31, 2025, we had various notes and bonds outstanding with terms, including fixed interest rate and principal payment terms, specific to each borrowing. Maturity dates for these long-term debt issuances range from 2026 to 2055. Total future interest payment obligations associated with these existing fixed-rate, long-term debt obligations were $4.0 billion as of December 31, 2025, with expected interest payment obligations of $329 million due within the next twelve months. Certain of our capital projects could be delayed if we experience difficulties in accessing capital. We expect to be able to obtain such additional financing, as needed, in amounts and upon terms that will be acceptable to us due to our strong credit ratings and our historical ability to obtain financing.

METC has a contractual obligation through December 31, 2050 for an Easement Agreement for transmission purposes and rights-of-way, leasehold interests, fee interests and licenses associated with the land over which the transmission lines cross. The cost for use of the rights-of-way is $10 million per year. See Note 17 to the consolidated financial statements for additional details related to the easement.

We have certain obligations including contingent liabilities and other current and long-term liabilities, that have uncertainty regarding the timing and any amount of future cash flows necessary to settle these obligations. Such items include:

•long-term incentive awards;

•pension and other postretirement obligations;

•regulatory liabilities related to asset removal costs and refundable income taxes; and

•liabilities to refund deposits from generators for transmission network upgrades.

Credit Ratings

Credit ratings by nationally recognized statistical rating agencies are an important component of our liquidity profile. Credit ratings relate to our ability to issue debt securities and the cost to borrow money and should not

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be viewed as a recommendation to buy, sell or hold securities. Ratings are subject to revision or withdrawal at any time and each rating should be evaluated independently of any other rating. An explanation of these ratings may be obtained from the respective rating agency. Our credit ratings as of December 31, 2025, were as follows:

S&P Global Ratings

Moody’s Investor Service, Inc.

Rating (a)

Outlook (b)

Rating

Outlook

ITC Holdings

Senior Unsecured Notes

BBB+

Stable

Baa2

Stable

Commercial Paper

A-2

Stable

Prime-2

Stable

ITCTransmission

First Mortgage Bonds

A+

Stable

METC

Senior Secured Notes

A+

Stable

ITC Midwest

First Mortgage Bonds

A+

Stable

ITC Great Plains

First Mortgage Bonds

A+

Stable

____________________________

(a)On March 3, 2025, S&P Global increased the First Mortgage Bonds and Senior Secured Notes ratings for each of our Regulated Operating Subsidiaries from A to A+.

(b)On November 6, 2025, S&P Global reaffirmed the ratings on ITC Holdings for each of our Regulated Operating Subsidiaries and revised all outlooks from negative to stable.

Covenants

Our debt instruments contain numerous financial and operating covenants that place significant restrictions on certain transactions, such as incurring additional indebtedness, engaging in sale and lease-back transactions, creating liens or other encumbrances, entering into mergers, consolidations, liquidations or dissolutions, creating or acquiring subsidiaries and selling or otherwise disposing of all or substantially all of our assets. In addition, the covenants require us to meet certain financial ratios, such as maintaining certain debt to capitalization ratios and certain funds from operations to debt levels. As of December 31, 2025, we were not in violation of any debt covenant. In the event of a downgrade in our credit ratings, none of the covenants would be directly impacted, although the borrowing costs under our revolving credit agreement may increase.

Cash Flows


	Year Ended						Percentage
	December 31,				Increase		Increase
(In millions of USD)	2025		2024		(Decrease)		(Decrease)
Cash Flows provided by (used in):
Operating activities	$	896	$	838	$	58	7	%
Investing activities	(1,320)		(1,076)		244		23	%
Financing activities	436		(68)		504		741	%
Net increase (decrease) in cash, cash equivalents and restricted cash	$	12	$	(306)

Cash Flows From Operating Activities

Net cash provided by operating activities increased primarily due to an increase in cash received from operating revenues of $131 million, a decrease in income taxes paid of $4 million and a decrease due to the settlement of interest rate swaps paid of $3 million during the year ended December 31, 2025 compared to the year ended December 31, 2024. This increase was partially offset by an increase in interest paid of $30 million, an increase in property taxes paid of $18 million, and an increase in ROE refunds, excluding interest, related to

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the October 2024 Order of $16 million, and a decrease in interest income of $9 million during the year ended December 31, 2025 compared to the year ended December 31, 2024.

Cash Flows From Investing Activities

Net cash used in investing activities increased primarily due to an increase in capital expenditures during the year ended December 31, 2025 compared to the year ended December 31, 2024.

Cash Flows From Financing Activities

Net cash provided by financing activities increased primarily due to a decrease in repayments of long-term debt of $525 million, an increase in net borrowings under our revolving credit agreement of $406 million, an increase in net issuances of commercial paper of $237 million, a decrease in dividend payments of $194 million, and a increase in net refundable deposits received from generators for transmission network upgrades of $21 million during the year ended December 31, 2025 compared to the year ended December 31, 2024. This increase was partially offset by a decrease in issuances of long-term debt of $884 million during the year ended December 31, 2025 compared to the year ended December 31, 2024.

Critical Accounting Estimates

The consolidated financial statements are prepared in accordance with GAAP. The preparation of these consolidated financial statements requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. The application of these policies requires judgments regarding future events.

These estimates and judgments, in and of themselves, could materially impact the consolidated financial statements and disclosures based on varying assumptions, as future events rarely develop exactly as forecasted, and even the best estimates routinely require adjustment.

The following accounting policies are the most significant to the portrayal of our financial condition and results of operations and/or that require management’s most difficult, subjective or complex judgments.

Regulation

Our Regulated Operating Subsidiaries are subject to rate regulation by the FERC. As a result, we apply accounting principles in accordance with the standards set forth by the FASB for accounting for the effects of certain types of regulation. Use of this accounting guidance results in differences in the application of GAAP between regulated and non-regulated businesses and requires the recording of regulatory assets and liabilities for certain transactions that would have been treated as expense or revenue in non-regulated businesses. As described in Note 7 to the consolidated financial statements, we had regulatory assets and liabilities of $225 million and $782 million, respectively, as of December 31, 2025. Future changes in the regulatory and competitive environments could result in discontinuing the application of the accounting standards for the effects of certain types of regulations. If we were to discontinue the application of this guidance on the operations of our Regulated Operating Subsidiaries, we may be required to record losses relating to certain regulatory assets or gains relating to certain regulatory liabilities. We also may be required to record losses of $14 million relating to intangible assets at December 31, 2025 that are included in other assets on the consolidated statements of financial position.

We believe that currently available facts support the continued applicability of the standards for accounting for the effects of certain types of regulation and that all regulatory assets and liabilities are recoverable or refundable under our current rate environment.

Revenue Recognition under Cost-Based Formula Rates with True-Up Mechanism

Our Regulated Operating Subsidiaries recover expenses and earn an authorized return on and recover investments in property, plant and equipment on a current basis, under their forward-looking cost-based Formula Rates with a true-up mechanism.

Under their Formula Rates, our Regulated Operating Subsidiaries use forecasted expenses, property, plant and equipment, point-to-point revenues and other items for the upcoming calendar year to establish their projected revenue requirement and for the MISO Regulated Operating Subsidiaries, their component of the billed network rates for service on their systems from January 1 to December 31 of that year. Our Formula Rates include a true-up mechanism, whereby our Regulated Operating Subsidiaries compare their actual

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revenue requirements to their billed revenues for each year to determine any over- or under-collection of revenue. The over- or under-collection typically results from differences between the projected revenue requirement used as the basis for billing and actual revenue requirement at each of our Regulated Operating Subsidiaries, or from differences between actual and projected monthly network peak loads at our MISO Regulated Operating Subsidiaries.

See Note 3 to the consolidated financial statements for a description of the policy for revenue recognition at our Regulated Operating Subsidiaries under their Formula Rates and Note 7 to the consolidated financial statements for the regulatory assets and liabilities recorded at our Regulated Operating Subsidiaries as a result of the Formula Rate revenue accruals and deferrals.

Contingent Obligations

See Note 3 to the consolidated financial statements for a description of the policy for estimating contingent obligations. The adequacy of liabilities recorded for contingent obligations can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect our consolidated financial statements. These events or conditions include, without limitation, the following:

•Changes in existing state or federal regulation by governmental authorities having jurisdiction over air quality, water quality, control of toxic substances, hazardous and solid wastes and other environmental matters;

•Changes in existing federal and state income tax laws;

•Identification and evaluation of lawsuits or complaints in which we may be or have been named as a defendant; and

•Resolution or progression of existing matters through the legislative process, the courts, the FERC, the NERC or the Environmental Protection Agency.

Pension and Postretirement Benefit Plan Assumptions

We sponsor certain retirement benefits for our employees, which include retirement pension plans and certain postretirement health care, dental and life insurance benefits. Our periodic costs and obligations associated with these plans are developed from actuarial valuations derived from a number of assumptions. Key assumptions include:

•Discount rates used to determine obligations - Benefit obligations, service cost and interest cost are determined by separately discounting projected benefit payments using a yield curve of high-quality corporate bonds. As of December 31, 2025, the weighted average single equivalent discount rate for the benefit obligation was 5.34% and 5.72% for our pension and postretirement benefit plans, respectively.

•Expected long-term returns on plan assets - In determining our long-term rate of return on plan assets, we consider the current and expected asset allocations, as well as historical and expected long-term rates of return on those types of asset classes. For the year ended December 31, 2025, we assumed that our pension and postretirement benefit plans’ assets would generate weighted average long-term rates of return of 7.00% and 5.20%, respectively.

•Rate of salary increases - As of December 31, 2025, we used an annual rate of salary increases of 4.50% to determine our pension and postretirement plan obligations.

•Mortality - The Pri-2012 mortality table projected forward generationally from 2012 with the MP-2020 mortality improvement scale was used to determine pension and postretirement plan obligations as of December 31, 2025.

•Rate of increase in health care costs - We used a health care cost trend rate of 6.75% for 2026 grading down to a 5.00% ultimate rate in 2033 in valuing our postretirement benefit obligation as of December 31, 2025. These rates are based on a review of recent and expected future experience.

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The below table displays the effect on our costs and obligation of a 1% change to certain pension and postretirement benefit plan assumptions as of December 31, 2025:


	Effect on Costs				Effect on Obligation
(In millions of USD)	1% Increase		1% Decrease		1% Increase		1% Decrease
Change to Pension Plans
Discount rate	$	(1)	$	—	$	(13)	$	16
Long-term rate of return on plan assets	(1)		1		N/A		N/A
Change to Postretirement Plan
Discount rate	(3)		4		(17)		21
Long-term rate of return on plan assets	(2)		2		N/A		N/A
Health care cost trend rate	4		(4)		19		(15)

See Note 11 to the consolidated financial statements for further details regarding our pension and postretirement benefit plan costs and obligations.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements that have or are reasonably likely to have a material effect on our financial condition.

Recent Accounting Pronouncements

See Note 2 to the consolidated financial statements for information related to recently issued and adopted FASB guidance.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Commodity Price Risk

We have commodity price risk at our Regulated Operating Subsidiaries arising from market price fluctuations for materials such as copper, aluminum, steel, oil and gas and other goods used in construction and maintenance activities. Higher costs of these materials are passed on to us by the contractors for these activities. These items affect only cash flows, as the amounts are included as components of net revenue requirement and any higher costs are included in rates under their cost-based Formula Rates.

Interest Rate Risk

Fixed Rate Debt

Based on the borrowing rates currently available for bank loans with similar terms and average maturities, the fair value of our consolidated long-term debt and debt maturing within one year, excluding borrowings on the revolving credit agreement and commercial paper, was $7,088 million and $6,918 million at December 31, 2025 and 2024, respectively. The total book value of our consolidated long-term debt and debt maturing within one year, net of discount and deferred financing fees and excluding borrowings on the revolving credit agreement and commercial paper, was $7,651 million and $7,645 million at December 31, 2025 and 2024, respectively. An increase in interest rates of 10% at December 31, 2025 and 2024 would decrease the fair value of debt by $267 million and $292 million, respectively, at that date, and a decrease in interest rates of 10% at December 31, 2025 and 2024 would increase the fair value of debt by $291 million and $319 million, respectively, at that date.

Revolving Credit Agreement

At December 31, 2025 and 2024, we had a consolidated total of $589 million and $247 million, respectively, outstanding under our revolving credit agreement, which is a variable rate loan. The fair value of the loan approximates book value based on the borrowing rates currently available for a variable rate loan obtained from third party lending institutions. A 10% increase or decrease in borrowing rates under the revolving credit agreement compared to the weighted average rates in effect at December 31, 2025 and 2024 would increase or decrease annual interest expense by $3 million and $1 million, respectively, at borrowing levels consistent with amounts outstanding at the end of each of the respective periods.

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Commercial Paper

At December 31, 2025, ITC Holdings had $237 million of commercial paper issued and outstanding under the commercial paper program. At December 31, 2024, ITC Holdings did not have any commercial paper issued and outstanding under the commercial paper program. Due to the short-term nature of these financial instruments, the carrying value approximates fair value. A 10% increase or decrease in annual interest rates for commercial paper compared to the weighted average interest rates in effect at December 31, 2025 would increase or decrease annual interest expense, net by $1 million, at levels consistent with amounts issued and outstanding at the end of the period.

Derivative Instruments and Hedging Activities

We use derivative financial instruments, including interest rate swap contracts and U.S. Treasury rate lock contracts, to manage our exposure to fluctuations in interest rates. The use of these financial instruments mitigates exposure to these risks and the variability of our operating results. We are not a party to leveraged derivatives and do not enter into derivative financial instruments for trading or speculative purposes.

During 2024, we terminated $300 million of 10-year U.S. Treasury rate lock contracts that managed interest rate risk associated with the ITC Holdings 5.65% Senior Notes, due May 9, 2034. During 2025, there were no interest rate swap contracts terminated. At December 31, 2025 and 2024, we held 5-year interest rate swap contracts with a notional amount of $755 million and $135 million, respectively, which manage interest rate risk associated with the forecasted future issuance of fixed-rate debt at ITC Holdings. See Note 9 to the consolidated financial statements for additional information.

Credit Risk

For the year ended December 31, 2024, our credit risk was primarily with DTE Electric, Consumers Energy and IP&L, which were responsible for approximately 23.0%, 21.9% and 22.7%, respectively, or $375 million, $357 million and $370 million, respectively, of our consolidated billed revenues. This portion of total billed revenues of DTE Electric, Consumers Energy and IP&L include the refund of 2022 revenue accruals and deferrals and exclude any amounts for the 2024 revenue accruals and deferrals that were included in our 2024 operating revenues but will not be billed to our customers until 2026.

See Note 6 to the consolidated financial statements for a discussion on the difference between billed revenues and operating revenues. Under DTE Electric’s and Consumers Energy’s current rate structure, DTE Electric and Consumers Energy include in their retail rates the actual cost of transmission services provided by ITCTransmission and METC, respectively, in their billings to their customers, effectively passing through to end-use consumers the total cost of transmission service. IP&L currently includes in their retail rates an allowance for transmission services provided by ITC Midwest in their billings to their customers. However, any financial difficulties experienced by DTE Electric, Consumers Energy or IP&L may affect their ability to make payments for transmission service to ITCTransmission, METC, and ITC Midwest, which could negatively impact our business. MISO, as our MISO Regulated Operating Subsidiaries’ billing agent, bills DTE Electric, Consumers Energy, IP&L and other customers on a monthly basis and collects fees for the use of the MISO Regulated Operating Subsidiaries’ transmission systems. SPP is the billing agent for ITC Great Plains and bills transmission customers for the use of ITC Great Plains transmission systems. MISO and SPP have implemented strict credit policies for its members’ customers, which include customers using our transmission systems. Specifically, MISO and SPP require a letter of credit or cash deposit equal to the credit exposure, which is determined by a credit scoring model and other factors, from any customer using a member’s transmission system.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

The following financial statements and schedules are included herein:


						Page
Management’s Report on Internal Control over Financial Reporting						41
Report of Independent Registered Public Accounting Firm (PCAOB ID No. 34)						42
Consolidated Statements of Financial Position as of December 31, 2025 and 2024						44
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2025, 2024 and 2023						45
Consolidated Statements of Changes in Stockholder’s Equity for the Years Ended December 31, 2025, 2024 and 2023						46
Consolidated Statements of Cash Flows for the Years Ended December 31, 2025, 2024 and 2023						47
Notes to Consolidated Financial Statements						48
Schedule I — Condensed Financial Information of Registrant						123

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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is designed to provide reasonable, not absolute, assurance as to the reliability of our financial reporting and the preparation of consolidated financial statements in accordance with generally accepted accounting principles. Internal control over financial reporting, no matter how well designed, has inherent limitations. Therefore, internal control over financial reporting determined to be effective can provide only reasonable assurance with respect to financial statement preparation and may not prevent or detect all misstatements.

Under management’s supervision, an evaluation of the design and effectiveness of our internal control over financial reporting was conducted based on the criteria set forth in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Our assessment included documenting, evaluating and testing of the design and operating effectiveness of our internal control over financial reporting. Based on this evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2025.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of

ITC Holdings Corp.

Novi, Michigan

Opinion on the Financial Statements

We have audited the accompanying consolidated statements of financial position of ITC Holdings Corp. and subsidiaries (the "Company") as of December 31, 2025 and 2024, the related consolidated statements of comprehensive income, changes in stockholder's equity, and cash flows, for each of the three years in the period ended December 31, 2025, and the related notes and the schedule listed in the Index at Item 15 (collectively referred to as the "financial statements"). In our opinion, the 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 its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

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

Critical Audit Matter

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

Regulatory Matters — Impact of rate regulation on the financial statements – Refer to Notes 3, 6, 7, and 17 to the financial statements

Critical Audit Matter Description

The Company’s Regulated Operating Subsidiaries are subject to rate regulation by the Federal Energy Regulatory Commission (the “regulatory agency”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. The cost-

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based Formula Rates at the Company’s Regulated Operating Subsidiaries recover expenses and earn an authorized return on, and recovery of the Company’s investments in property, plant and equipment on a current basis and include a true-up mechanism. Regulatory decisions and legal challenges can have an impact on rates, recovery of certain costs, including the costs of transmission assets and regulatory assets, operating-related matters, timing of actual collections or refunds, and the return on equity. Accounting for the economics of rate regulation impacts certain financial statement line items and disclosures.

We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about certain impacted account balances and disclosures and the high degree of subjectivity involved in assessing the potential impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of recovery of costs incurred or potential refunds to customers. Although the Company expects to recover costs from customers through regulated rates, there is a risk that the formula inputs, including the return on equity, remain subject to legal challenges through the regulatory process. The Company uses the formula inputs to calculate annual revenue requirements unless the regulatory agency determines the resulting rates to be unjust and unreasonable. Auditing these judgments required especially subjective judgment and specialized knowledge of accounting for rate regulation and the rate-setting process due to their inherent complexities.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the impact of rate regulation and the uncertainty of future decisions by the regulatory agency included the following, among others:

•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the recognition of regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.

•We assessed relevant regulatory orders and interpretations, as well as, utility and intervener filings, legal decisions, and other publicly available information to evaluate the likelihood of recovery of costs incurred or potential refunds to customers.

•For regulatory matters in process, we inspected the annual formula rate filings and open complaints for any evidence that might contradict management’s assertions. We obtained and evaluated an analysis from management, regarding cost recoveries or potential future reduction in rates.

•We obtained letters from the Company’s internal and external legal counsel to assess management’s conclusions and disclosures.

•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.

/s/ DELOITTE & TOUCHE LLP

Detroit, Michigan

February 11, 2026

We have served as the Company’s auditor since 2001.

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ITC HOLDINGS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION


	December 31,
(In millions of USD, except share data)	2025		2024
ASSETS
Current assets
Cash and cash equivalents	$	13	$	19
Accounts receivable	164		160
Inventory	85		78
Regulatory assets	28		21
Prepaid and other current assets	28		23
Total current assets	318		301
Property, plant and equipment (net of accumulated depreciation and amortization of $2,892 and $2,715, respectively)	13,196		12,129
Other assets
Goodwill	950		950
Regulatory assets	197		187
Other assets	173		154
Total other assets	1,320		1,291
TOTAL ASSETS	$	14,834	$	13,721
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities
Accounts payable	$	141	$	142
Accrued compensation	71		57
Accrued interest	77		77
Accrued taxes	81		77
Regulatory liabilities	23		67
Refundable deposits and advances for construction	54		44
Debt maturing within one year	636		—
Other current liabilities	25		20
Total current liabilities	1,108		484
Accrued pension and postretirement liabilities	27		39
Deferred income taxes	1,662		1,521
Regulatory liabilities	759		729

Long-term debt	7,840		7,892
Other liabilities	81		62
Commitments and contingent liabilities (Notes 6 and 17)
TOTAL LIABILITIES	11,477		10,727
STOCKHOLDER’S EQUITY
Common stock, without par value, 235,000,000 shares authorized, 224,203,112 shares issued and outstanding at December 31, 2025 and 2024	892		892
Retained earnings	2,444		2,074
Accumulated other comprehensive income	21		28
Total stockholder’s equity	3,357		2,994
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	14,834	$	13,721

See notes to consolidated financial statements.

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ITC HOLDINGS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


	Year Ended December 31,
(In millions of USD)	2025		2024		2023
OPERATING REVENUES
Transmission and other services	$	1,775	$	1,613	$	1,562
Formula Rate true-up	11		12		(17)
Total operating revenues	1,786		1,625		1,545
OPERATING EXPENSES
Operation and maintenance	116		111		109
General and administrative	153		121		111
Depreciation and amortization	349		326		307
Taxes other than income taxes	181		154		145
Other operating expenses (income), net	—		(1)		(1)
Total operating expenses	799		711		671
OPERATING INCOME	987		914		874
OTHER EXPENSES (INCOME)
Interest expense, net	364		348		315
Allowance for equity funds used during construction	(44)		(44)		(43)
Other expenses (income), net	(11)		(22)		(17)
Total other expenses (income)	309		282		255
INCOME BEFORE INCOME TAXES	678		632		619
INCOME TAX PROVISION	159		148		156
NET INCOME	519		484		463
OTHER COMPREHENSIVE (LOSS) INCOME
Derivative instruments, net of tax	(7)		(1)		2
TOTAL OTHER COMPREHENSIVE (LOSS) INCOME, NET OF TAX	(7)		(1)		2
TOTAL COMPREHENSIVE INCOME	$	512	$	483	$	465

See notes to consolidated financial statements.

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ITC HOLDINGS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY


					Accumulated
					Other		Total
	Common		Retained		Comprehensive		Stockholder's
(In millions of USD)	Stock		Earnings		Income		Equity

BALANCE, DECEMBER 31, 2022	$	892	$	1,753	$	27	$	2,672

Net income	—		463		—		463


Dividends to ITC Investment Holdings	—		(283)		—		(283)






Other comprehensive income, net of tax	—		—		2		2

BALANCE, DECEMBER 31, 2023	$	892	$	1,933	$	29	$	2,854

Net income	—		484		—		484
Dividends to ITC Investment Holdings	—		(343)		—		(343)
Other comprehensive loss, net of tax	—		—		(1)		(1)
BALANCE, DECEMBER 31, 2024	$	892	$	2,074	$	28	$	2,994

Net income	—		519		—		519
Dividends to ITC Investment Holdings	—		(149)		—		(149)
Other comprehensive loss, net of tax	—		—		(7)		(7)
BALANCE, DECEMBER 31, 2025	$	892	$	2,444	$	21	$	3,357

See notes to consolidated financial statements.

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ITC HOLDINGS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Year Ended December 31,
(In millions of USD)	2025		2024		2023
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	519	$	484	$	463
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	349		326		307
Recognition, refund and collection of revenue accruals and deferrals — including accrued interest	(31)		(20)		8
Deferred income tax expense	119		93		105
Allowance for equity funds used during construction	(44)		(44)		(43)

Share-based compensation	37		15		15
Other	(4)		(15)		10
Changes in assets and liabilities, exclusive of changes shown separately:
Accounts receivable	(11)		(13)		2



Accounts payable	2		8		(4)
Accrued interest	—		(3)		12
Accrued compensation	(4)		(7)		(9)
Accrued taxes	4		3		3

Other current and non-current assets and liabilities, net	(40)		11		(20)
Net cash provided by operating activities	896		838		849
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(1,315)		(1,062)		(818)

Other	(5)		(14)		(18)
Net cash used in investing activities	(1,320)		(1,076)		(836)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuances of long-term debt, net	—		884		889
Borrowings under revolving credit agreements	1,522		1,134		1,196

Net issuance (repayments) of commercial paper	237		—		(134)
Repayments of long-term debt	—		(525)		(250)
Repayments of revolving credit agreements	(1,180)		(1,198)		(1,093)

Dividends to ITC Investment Holdings	(149)		(343)		(283)
Refundable deposits from generators for transmission network upgrades	29		9		34
Repayments of refundable deposits from generators for transmission network upgrades	(22)		(23)		(35)

Other	(1)		(6)		(10)
Net cash provided by (used in) financing activities	436		(68)		314
NET INCREASE (DECREASE) IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH	12		(306)		327
CASH, CASH EQUIVALENTS AND RESTRICTED CASH — Beginning of period	27		333		6
CASH, CASH EQUIVALENTS AND RESTRICTED CASH — End of period	$	39	$	27	$	333

See notes to consolidated financial statements.

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ITC HOLDINGS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. GENERAL

ITC Holdings and its subsidiaries are engaged in the transmission of electricity in the United States. ITC Holdings is a wholly-owned subsidiary of ITC Investment Holdings. Fortis owns a majority indirect equity interest in ITC Investment Holdings, with GIC holding an indirect, passive, non-voting equity interest of 19.9%. Through our Regulated Operating Subsidiaries, we own, operate, maintain and invest in high-voltage transmission systems in Michigan’s Lower Peninsula and portions of Iowa, Minnesota, Illinois, Missouri, Kansas, Oklahoma and Wisconsin that transmit electricity from generating stations to local distribution facilities connected to our transmission systems.

Our Regulated Operating Subsidiaries are independent electric transmission utilities, with cost-based rates regulated by the FERC. ITCTransmission’s service area is located in southeastern Michigan, while METC’s service area covers approximately two-thirds of Michigan’s Lower Peninsula and is contiguous with ITCTransmission’s service area. ITC Midwest’s service area is located in portions of Iowa, Minnesota, Illinois, Missouri and Wisconsin. ITC Great Plains currently owns assets located in Kansas and Oklahoma.

2. RECENT ACCOUNTING PRONOUNCEMENTS

Recently Adopted Pronouncements

Enhancements to Income Tax Disclosures

In December 2023, the FASB issued authoritative guidance modifying the disclosure requirements for income tax. This update is intended to provide investors information to better assess how an entity’s operations and related tax risks, tax planning and operational opportunities affect its tax rate and prospects for future cash flows. Notable changes include disaggregation of income tax information by jurisdiction and changes to the presentation of information for the reconciliation of effective tax rates. We have adopted this new authoritative guidance effective January 1, 2025, and it is reflected in our consolidated financial statements on a retrospective basis. See Notes 10 and 18 for affected disclosures.

Recently Issued Pronouncements

Disaggregation of Income Statement Expenses

In November 2024, the FASB issued authoritative guidance requiring public entities to, on an annual and interim basis, disaggregate certain income statement expense captions into specified categories within the footnotes to the financial statements. This update is intended to provide investors with more detailed information about the types of expenses in commonly presented expense captions such as cost of sales, selling, general and administrative expenses and research and development. The guidance requires disclosure which disaggregates, in a tabular presentation, each relevant expense caption on the face of the income statement that includes any of the following expenses: purchases of inventory; employee compensation; depreciation; intangible asset amortization; and depreciation, depletion and amortization recognized as part of oil- and gas-producing activities or other types of depletion expenses. The tabular disclosure would also include amounts that are already required to be disclosed under current GAAP, as applicable. The guidance also requires the disclosure of a qualitative description of the amounts remaining in relevant expense captions that are not separately disaggregated quantitatively and the total amount of an entity’s selling expenses. The guidance is effective for fiscal years beginning after December 15, 2026, and interim periods within fiscal years beginning after December 15, 2027, on a prospective basis, with retrospective application and early adoption permitted. We are evaluating the impact of the new guidance on our disclosures.

Targeted Improvements to the Accounting for Internal-Use Software

In September 2025, the FASB issued authoritative guidance which amends certain aspects of the accounting for and disclosure of software costs. This update is intended to modernize the guidance to reflect the software development approaches currently used. The guidance revises criteria for capitalizing internal software development costs by removing development stage guidance, introducing a probable-to-complete recognition threshold and requiring the resolution of significant development uncertainty before capitalization. The guidance is effective for fiscal years beginning after December 15, 2027 and interim periods within those annual reporting

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periods. Adoption is permitted on a prospective basis, a modified transition approach based on the status of in-process projects, or with retrospective application. Early adoption is permitted. We are evaluating the impact of the new guidance on our accounting and disclosures.

3. SIGNIFICANT ACCOUNTING POLICIES

A summary of the major accounting policies followed in the preparation of the accompanying consolidated financial statements, which conform to GAAP, is presented below:

Principles of Consolidation — ITC Holdings consolidates its majority owned subsidiaries. We eliminate all intercompany balances and transactions.

Use of Estimates — The preparation of the consolidated financial statements requires us to use estimates and assumptions that impact the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results may differ from our estimates.

Regulation — Our Regulated Operating Subsidiaries are subject to the regulatory jurisdiction of the FERC, which issues orders pertaining to rates, recovery of certain costs, including the costs of transmission assets and regulatory assets, conditions of service, accounting, financing authorization and operating-related matters. The utility operations of our Regulated Operating Subsidiaries meet the accounting standards set forth by the FASB for the accounting effects of certain types of regulation. These accounting standards recognize the cost-based rate setting process, which results in differences in the application of GAAP between regulated and non-regulated businesses. These standards require the recording of regulatory assets and liabilities for certain transactions that would have been recorded in the statements of comprehensive income in non-regulated businesses. Regulatory assets represent costs that will be included as a component of future tariff rates and regulatory liabilities represent amounts provided in the current tariff rates that are intended to recover costs expected to be incurred in the future or amounts to be refunded to customers.

Cash and Cash Equivalents — We consider all unrestricted highly-liquid temporary investments with an original maturity of three months or less at the date of purchase to be cash equivalents.

Restricted Cash — Restricted cash includes cash that is legally or contractually restricted for use or withdrawal or formally set aside for a specific purpose. Restricted cash primarily represents cash on deposit to pay for vegetation management, land easements and land purchases for the purpose of transmission line construction as well as amounts liquidated to make benefit payments related to our supplemental benefit plans.

Inventories — Materials and supplies inventories are valued at average cost. Additionally, the costs of warehousing activities are recorded here and included in the cost of materials when requisitioned.

Property, Plant and Equipment — Property, plant and equipment at our Regulated Operating Subsidiaries, including capital equipment expected to be used exclusively for capital projects, is stated at its original cost when first devoted to utility service. The gross book value of assets retired less salvage proceeds is charged to accumulated depreciation. The provision for depreciation of transmission assets is a significant component of our Regulated Operating Subsidiaries’ cost of service under FERC-approved rates. Periodically, we perform depreciation studies of the assets at our Regulated Operating Subsidiaries. The results of these studies are submitted to and require approval from the FERC prior to changing our depreciation rates. Depreciation is computed over the estimated useful lives of the assets using the straight-line method for financial reporting purposes and accelerated methods for income tax reporting purposes. The composite depreciation rate for our Regulated Operating Subsidiaries included in our consolidated statements of comprehensive income was 2.4% for each of the years ended December 31, 2025, 2024 and 2023. The composite depreciation rates include depreciation primarily on transmission station equipment, towers, poles and overhead and underground lines that have a useful life ranging from 43 to 70 years. The portion of depreciation expense related to asset removal costs is added to regulatory liabilities or deducted from regulatory assets and removal costs incurred are deducted from regulatory liabilities or added to regulatory assets.

For acquisitions of property, plant and equipment greater than the net book value (other than asset acquisitions accounted for under the purchase method of accounting that result in goodwill), the

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acquisition premium is recorded to property, plant and equipment and amortized over the estimated remaining useful lives of the assets using the straight-line method for financial reporting purposes and accelerated methods for income tax reporting purposes.

Property, plant and equipment not recorded at our Regulated Operating Subsidiaries is stated at its acquired cost. Proceeds from salvage less the net book value of the disposed assets is recognized as a gain or loss on disposal. Depreciation is computed based on the acquired cost less expected residual value and is recognized over the estimated useful lives of the assets on a straight-line method for financial reporting purposes and accelerated methods for income tax reporting purposes.

Generator Interconnection Projects and Contributions in Aid of Construction — Certain capital investment at our Regulated Operating Subsidiaries relates to investments made under GIAs. The GIAs typically consist of both transmission network upgrades, which are a category of upgrades deemed by the FERC to benefit the transmission system as a whole, as well as direct connection facilities, which are necessary to interconnect the generating facility to the transmission system and primarily benefit the generating facility. GIAs typically require the generator to make a contribution in aid of construction to our Regulated Operating Subsidiaries to cover the cost of certain investments made by us as part of the agreement. However, we may fund construction of certain projects without contributions from the generators.

Our investments in transmission facilities are recorded to property, plant and equipment, and are recorded net of any contribution in aid of construction. We also receive refundable deposits from the generator for certain investment in network upgrade facilities in advance of construction, which are recorded to current or non-current liabilities depending on the expected refund date.

Jointly Owned Utility Plant/Coordinated Services — Our Regulated Operating Subsidiaries have agreements with other utilities for the joint ownership of assets as described in Note 15. We account for these jointly owned assets by recording property, plant and equipment for the percentage of our undivided ownership interest. Various agreements provide the authority for construction of capital improvements and the operating costs associated with the transmission assets. Generally, each party is responsible for the capital, operation and maintenance, and other costs of these jointly owned facilities based upon each participant’s undivided ownership interest, and each participant is responsible for providing its own financing. Our participating share of expenses associated with these jointly held assets is primarily recorded within operation and maintenance expense in our consolidated statements of comprehensive income.

Fair Value Through Net Income — We have certain investments in mutual funds, including fixed income securities and equity securities, that are classified as fair value through net income. The investments fund our two supplemental nonqualified, noncontributory retirement benefit plans for selected management employees as described in Note 11, as well as other deferred compensation plans. Gains and losses associated with these investments are recorded in other expenses (income), net in the consolidated statements of comprehensive income.

Impairment of Long-Lived Assets — Other than goodwill, our long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate the carrying amount of an asset may not be recoverable. If the carrying amount of the asset exceeds the expected undiscounted future cash flows generated by the asset, the asset is written down to its estimated fair value and an impairment loss is recognized in our consolidated statements of comprehensive income.

Goodwill — Goodwill is not subject to amortization; however, goodwill is required to be assessed for impairment, and a resulting write-down, if any, is to be reflected in operating expenses. We have goodwill recorded relating to our acquisitions of ITCTransmission and METC, and ITC Midwest’s acquisition of the IP&L transmission assets. Goodwill is reviewed at the reporting unit level at least annually for impairment and whenever facts or circumstances indicate that the value of goodwill may be impaired. Our reporting units are ITCTransmission, METC and ITC Midwest as each entity represents an individual operating segment to which goodwill has been assigned. At December 31, 2025 and 2024, we had goodwill balances recorded at ITCTransmission, METC and ITC Midwest of $173 million, $454 million and $323 million, respectively.

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In order to perform an impairment analysis, we have the option of performing a qualitative assessment to determine whether the existence of events or circumstances leads to a determination that it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, in which case no further testing is required. If an entity bypasses the qualitative assessment or performs a qualitative assessment but determines that it is more likely than not that a reporting unit’s fair value is less than its carrying amount, a quantitative, fair value-based test is performed to assess and measure goodwill impairment, if any. If a quantitative assessment is performed, we determine the fair value of our reporting units using valuation techniques based on discounted future cash flows under various scenarios and consider estimates of market-based valuation multiples for companies within the peer group of our reporting units.

We completed our annual goodwill impairment test for our reporting units as of October 1, 2025 and determined that no impairment exists. There were no events subsequent to October 1, 2025 that indicated impairment of our goodwill.

Deferred Financing Fees and Discount on Debt — Costs related to the issuance of long-term debt are generally recorded as a direct deduction from the carrying amount of the related debt and amortized over the life of the debt. Debt issuance costs incurred prior to the associated debt funding are presented as an asset. Unamortized debt issuance costs associated with the revolving credit agreement, commercial paper and other similar arrangements are presented as an asset (regardless of whether there are any amounts outstanding under those credit facilities) and amortized over the life of the particular arrangement. The debt discount related to the issuance of long-term debt is recorded to long-term debt and amortized over the life of the debt.

Asset Retirement Obligations — A conditional asset retirement obligation is a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within our control. We have identified conditional asset retirement obligations primarily associated with the removal of equipment containing polychlorinated biphenyls and asbestos. We record a liability at fair value for a legal asset retirement obligation in the period in which it is incurred. When a new legal obligation is recorded, we capitalize the costs of the liability by increasing the carrying amount of the related long-lived asset. We accrete the liability to its present value each period and depreciate the capitalized cost over the useful life of the related asset. At the end of the asset’s useful life, we settle the obligation for its recorded amount. We recognize regulatory assets for the timing differences between the incurred costs to settle our legal asset retirement obligations and the recognition of such obligations as applicable for our Regulated Operating Subsidiaries. Our asset retirement obligations of $4 million as of December 31, 2025 and 2024, are included in other liabilities on the consolidated statements of financial position.

Derivatives and Hedging — We may use derivative financial instruments to manage our exposure to fluctuations in interest rates. For derivative instruments that have been designated and qualify as cash flow hedges of the exposure to variability in expected future cash flows, the unrealized gain or loss on the derivative is initially reported, net of tax, as a component of other comprehensive income (loss) and reclassified to the consolidated statements of comprehensive income when the underlying hedged transaction affects net income. Cash flows related to derivative instruments are classified in the consolidated statements of cash flows within cash flows from operating activities. The fair values of derivatives are recognized as current or long-term assets and liabilities depending on the timing of settlements and resulting cash flows. See Note 9 for information regarding derivative instruments.

Contingent Obligations — We are subject to a number of federal and state laws and regulations, as well as other factors and conditions that potentially subject us to environmental, litigation, income tax and other contingencies. We periodically evaluate our exposure to such contingencies and record liabilities for those matters where a loss is considered probable and reasonably estimable and disclose matters that are considered probable but not reasonably estimable. We reverse the liabilities recorded for those matters when a loss is no longer considered probable or the liabilities are otherwise settled. Our liabilities exclude any estimates for legal costs not yet incurred associated with handling these matters, which could be material. The adequacy of liabilities recorded can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect our consolidated financial statements.

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Revenues — Substantially all of our revenue from contracts with customers is generated from providing transmission services to customers as services are provided based on our FERC-approved cost-based Formula Rates. We record a reserve for revenue subject to refund when such refund is probable and can be reasonably estimated. This reserve is recorded as a reduction to operating revenues.

The cost-based Formula Rates at our Regulated Operating Subsidiaries include a true-up mechanism that compares the actual revenue requirements of our Regulated Operating Subsidiaries to their billed revenues for each year to determine any over- or under-collection of revenue requirements and we record a revenue deferral or accrual for the difference. The true-up mechanisms under our Formula Rates are considered alternative revenue programs of rate-regulated utilities. Operating revenues arising from these alternative revenue programs are presented in our consolidated statements of comprehensive income in the line “Formula Rate true-up”, which is separate from the reporting of our tariff revenues, which are presented in the line “Transmission and other services.” Only the initial origination of our alternative revenue program revenue is reported in the Formula Rate true-up line in our consolidated statements of comprehensive income. When those amounts are subsequently included in the price of utility service and billed or refunded to customers, we account for that event as the recovery or settlement of the associated regulatory asset or regulatory liability, respectively. See Note 6 under “Cost-Based Formula Rates with True-Up Mechanism” and Note 4 under “Formula Rate True-Up” for a discussion of our revenue accounting under our cost-based Formula Rates.

Share-Based Payment — Under long-term incentive plans, we grant long-term incentive awards consisting of PBUs and SBUs to employees, including executive officers, of ITC Holdings. For awards granted prior to 2024, each PBU and SBU granted is valued based on one share of Fortis common stock traded on the Toronto Stock Exchange, converted to U.S. dollars and generally settled only in cash. For grant years beginning in 2024, each PBU and SBU granted is valued based on one share of Fortis common stock traded on the NYSE and generally settled only in cash. However, certain SBUs granted to the executives may settle only in cash, 100% Fortis common stock, or 50% cash and 50% Fortis common stock depending on executives’ settlement elections and whether certain share ownership requirements are met. All PBUs and SBUs are classified as liability awards and generally vest on the third January 1st following the grant date, provided the service and performance criteria, as applicable, are satisfied, and will be settled during the same quarter. However, certain awards may vest over a different period or on the grant date based on retirement eligibility criteria or other award terms. The PBUs and SBUs earn dividend equivalents, which are also re-measured and settled consistent with the target award at the end of the vesting period. The granted awards and related dividend equivalents have no shareholder rights.

Compensation cost is recognized over the expected vesting period and remeasured each reporting period based on Fortis’ stock price. The PBUs are also remeasured each reporting period based on the applicable market and performance conditions in the awards. Compensation cost is adjusted for forfeitures in the period in which they occur and the final measure of compensation cost for the awards is based on the cash settlement amount.

See Note 14 for additional discussion of the plans.

Comprehensive Income (Loss) — Comprehensive income (loss) is the change in stockholder’s equity during a period arising from transactions and events from non-owner sources, including net income and any gain or loss arising from derivative financial instruments.

Income Taxes — Deferred income taxes are recognized for the expected future tax consequences of events that have been recognized in the consolidated financial statements or tax returns. Deferred income tax assets and liabilities are determined based on the differences between the financial statements and the tax bases of various assets and liabilities, using the tax rates expected to be in effect for the year in which the differences are expected to reverse, and classified as non-current on our consolidated statements of financial position.

The accounting standards for uncertainty in income taxes prescribe a recognition threshold and a measurement attribute for tax positions taken, or expected to be taken, in a tax return that may not be sustainable. As of December 31, 2025, we have not recognized any uncertain income tax positions.

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We are a part of the FortisUS consolidated federal and Michigan income tax returns and we are a party to an intercompany tax sharing agreement that establishes the method for determining tax liabilities that are due and allocating tax attributes that are utilized on the consolidated income tax returns. We continue to file with various other state and city jurisdictions where we have a separate return filing obligation. The FortisUS consolidated federal tax returns are no longer subject to U.S. federal tax examinations for tax years 2021 and earlier. State and city jurisdictions that remain subject to examination range from tax years 2021 to 2024. In the event we are assessed interest or penalties by any income tax jurisdictions, interest and penalties would be recorded to interest expense, net and other expenses (income), net, respectively, in our consolidated statements of comprehensive income. See Notes 10 and 18 for additional discussion on income taxes.

4. REVENUE

Transmission Services

Through our Regulated Operating Subsidiaries, we generate nearly all our revenue from providing electric transmission services over our transmission systems. As independent transmission companies, our transmission services are provided and revenues are received based on our tariffs, as approved by the FERC. We recognize revenue for transmission services over time as transmission services are provided to customers (generally using an output measure of progress based on transmission load delivered). Customers simultaneously receive and consume the benefits provided by our Regulated Operating Subsidiaries’ services. We recognize revenue in the amount to which we have the right to invoice because we have a right to consideration in an amount that corresponds directly with the value to the customer of performance completed to date. As billing agents, MISO and SPP independently bill our customers on a monthly basis and collect fees for the use of our transmission systems. No component of the transaction price is allocated to unsatisfied performance obligations.

Transmission service revenue includes an estimate for unbilled revenues from service that has been provided but not billed by the end of an accounting period. Unbilled revenues are dependent upon a number of factors that require management’s judgment including estimates of transmission network load (for the MISO Regulated Operating Subsidiaries) and preliminary information provided by billing agents. Due to the seasonal fluctuations of actual load, the unbilled revenue amount generally increases during the spring and summer and decreases during the fall and winter. See Note 5 for balances of unbilled accounts receivable.

Formula Rate True-Up

The true-up mechanism under our Formula Rates is considered an alternative revenue program of a rate-regulated utility given it permits our Regulated Operating Subsidiaries to adjust future rates in response to past activities or completed events in order to collect our actual revenue requirements under our Formula Rates. In accordance with our accounting policy, only the current year origination of the true-up is reported as a Formula Rate true-up. See Note 6 for more information on our Formula Rates.

Other Services

Other services revenue consists of rental revenues, easement revenues, amounts from providing ancillary services relating to customer-owned plant assets and generator interconnection annual maintenance fees. A portion of other services revenue is treated as a revenue credit and taken as a reduction to gross revenue requirement when calculating net revenue requirement under our Formula Rates. Total other services revenue included in transmission and other services in the consolidated statements of comprehensive income was $4 million for each of the years ended December 31, 2025 and 2024 and $6 million for the year ended December 31, 2023.

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5. ACCOUNTS RECEIVABLE

The following table presents the components of accounts receivable on the consolidated statements of financial position:


	December 31,
(In millions of USD)	2025		2024
Trade accounts receivable	$	9	$	2
Unbilled accounts receivable	138		135

Other	17		23
Total accounts receivable	$	164	$	160

6. REGULATORY MATTERS

Cost-Based Formula Rates with True-Up Mechanism

Our Regulated Operating Subsidiaries recover expenses and earn an authorized return on and recover investments in property, plant and equipment using cost-based Formula Rates. Each of our Regulated Operating Subsidiaries separately calculates a transmission revenue requirement under their cost-based formula based on financial information specific to each company. The calculation of projected revenue requirement for a future period, generally a calendar year, is used to establish the transmission rate used for billing purposes. The transmission revenue requirements at our Regulated Operating Subsidiaries are set annually and remain in effect for a one-year period. By updating the inputs to the formula and resulting rates on an annual basis, the revenues at our Regulated Operating Subsidiaries reflect changing operational data and financial performance, including the amount of network load on their transmission systems (for our MISO Regulated Operating Subsidiaries), operating expenses and additions to property, plant and equipment when placed in service, among other items.

The formula used to derive the rates does not require further action or FERC filings each year, although the formula inputs remain subject to legal challenge at the FERC. Our Regulated Operating Subsidiaries will continue to use the formula to calculate their respective annual revenue requirements unless the FERC determines the resulting rates to be unjust and unreasonable and another mechanism is determined by the FERC to be just and reasonable. See Note 17 for details on the MISO ROE Complaints.

The cost-based Formula Rates at our Regulated Operating Subsidiaries include a true-up mechanism that compares the actual revenue requirements of our Regulated Operating Subsidiaries to their billed revenues for each year to determine any over- or under-collection of revenue requirements. Revenue is recognized for services provided during each reporting period based on actual revenue requirements calculated using the formula. Our Regulated Operating Subsidiaries accrue or defer revenues to the extent that the actual revenue requirement for the reporting period is higher or lower, respectively, than the amounts billed relating to that reporting period. The amount of accrued or deferred revenues is reflected in future revenue requirements and thus flows through to customer bills within two years under the provisions of our Formula Rates. This annual true-up ensures that our Regulated Operating Subsidiaries recover their allowed costs and earn their authorized returns while also ensuring that our customers pay the actual revenue requirement. We do not earn a return on the balance of regulatory assets for revenue accruals. Interest is accrued on the principal amounts of the revenue accruals and deferrals. The accrued interest is subject to rate recovery along with the principal amount of the revenue accrual or subject to refund through rates along with the principal amount of revenue deferrals in future periods.

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The net changes in regulatory assets and liabilities associated with our Regulated Operating Subsidiaries’ Formula Rate revenue accruals and deferrals, including accrued interest, were as follows during the year ended December 31, 2025:


(In millions of USD)	Total
Net regulatory liabilities as of December 31, 2024	$	(8)
Net refund of 2023 revenue deferrals and accruals, including accrued interest	21
Net revenue accruals, including accrued interest	11
Net accrued interest payable	(1)
Net regulatory assets as of December 31, 2025	$	23

ROE and Incentive Adders for Transmission Rates

The FERC has authorized the use of ROE incentives, or adders, that can be applied to the rates of TOs when certain conditions are met. Our MISO Regulated Operating Subsidiaries and ITC Great Plains utilize ROE adders related to independent transmission ownership and RTO participation. The FERC issued a NOPR on March 20, 2020, and a supplemental NOPR on April 15, 2021, proposing to update its transmission incentives policy to remove incentives for independent transmission ownership and RTO participation and to grant incentives for certain transmission projects. As of December 31, 2025, no final determination had been made on these NOPRs and we cannot predict whether this will have a material impact on us.

MISO Regulated Operating Subsidiaries

Prior to the issuance of the October 2024 Order, the authorized ROE used by the MISO Regulated Operating Subsidiaries was 10.77% and was composed of a base ROE of 10.02% with a 25 basis point adder for independent transmission ownership and a 50 basis point adder for RTO participation. Based on the October 2024 Order, the authorized ROE used by the MISO Regulated Operating Subsidiaries was revised to 10.73% and is composed of a base ROE of 9.98% with a 25 basis point adder for independent transmission ownership and a 50 basis point adder for RTO participation. See Note 17 for a discussion regarding the October 2024 Order and the related aggregate refund liability.

ITC Great Plains

The authorized ROE used by ITC Great Plains was 11.41% and is composed of a base ROE of 10.66% with a 25 basis point adder for independent transmission ownership and a 50 basis point adder for RTO participation.

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7. REGULATORY ASSETS AND LIABILITIES

The following table summarizes the regulatory asset and liability balances:


	December 31,
(In millions of USD)	2025		2024
Regulatory assets:
Current:
Revenue accruals (including accrued interest of $2 and $2, respectively) (a)	$	28	$	21

Total current	28		21
Non-current:
Revenue accruals (including accrued interest of $1 and $1, respectively) (a)	33		26



Income taxes recoverable related to AFUDC equity	153		141

Pensions and postretirement	1		8


Other	10		12
Total non-current	197		187
Total regulatory assets	$	225	$	208
Regulatory liabilities:
Current:
Revenue deferrals (including accrued interest of $2 and $4, respectively) (a)	$	16	$	40
Refund related to the October 2024 Order (including accrued interest of $2 and $6, respectively) (b)	7		27

Total current	23		67
Non-current:
Revenue deferrals (including accrued interest of $1 and $1, respectively) (a)	22		15
Pensions and postretirement	73		68
Accrued asset removal costs	172		141
Refundable excess deferred state income taxes	51		52
Refundable excess deferred federal income taxes	441		453

Total non-current	759		729
Total regulatory liabilities	$	782	$	796

____________________________

(a)Refer to discussion of revenue accruals and deferrals in Note 6 under “Cost-Based Formula Rates with True-Up Mechanism.”

(b)Refer to discussion of the refund liability in Note 17 under “Rate of Return of Equity Complaints.”

Income Taxes Recoverable Related to AFUDC Equity

Accounting standards for income taxes provide that a regulatory asset be recorded if it is probable that a future increase in taxes payable, relating to the book depreciation of AFUDC equity that has been capitalized to property, plant and equipment, will be recovered from customers through future rates. The regulatory asset for the tax effects of AFUDC equity is recovered over the life of the underlying book asset in a manner that is consistent with the depreciation of the AFUDC equity that has been capitalized to property, plant and equipment.

Pensions and Postretirement

Accounting standards for defined benefit pension and other postretirement plans for rate-regulated entities allow for amounts that otherwise would have been recorded to AOCI to be recorded as regulatory assets or

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liabilities, as appropriate. As the unrecognized amounts recorded to these regulatory assets and liabilities are recognized, the amounts will be recovered from or returned to customers in future rates under our cost-based Formula Rates.

Accrued Asset Removal Costs

The carrying amount of the accrued asset removal costs represents the difference between incurred costs to remove property, plant and equipment and the estimated removal costs included and collected in rates. The portions of depreciation expense included in our depreciation rates related to asset removal costs are recorded as increases to the related regulatory liability. Removal costs incurred reduce the related regulatory liability.

Refundable Excess Deferred State Income Taxes

As a result of reductions in corporate income tax rates in certain states we operate in, we were required to revalue our deferred tax balances at the new corporate income tax rates, which resulted in lower net deferred tax liabilities and the recording of a regulatory liability for excess deferred taxes at certain of our Regulated Operating Subsidiaries. Amortization of the excess deferred taxes is determined based on the remaining book lives of utility plant. During each of the years ended December 31, 2025 and 2024, we recorded $1 million of amortization related to the excess deferred taxes to income tax provision in our consolidated statements of comprehensive income.

Refundable Excess Deferred Federal Income Taxes

Under the Tax Cuts and Jobs Act of 2017, we were required to revalue our deferred tax assets and liabilities at the new federal corporate income tax rate as of the date of the enactment of the act, which resulted in lower net deferred tax liabilities and the establishment of a net regulatory liability for excess deferred taxes at our Regulated Operating Subsidiaries. Amortization of the excess deferred taxes is determined based on a method associated with the related public utility property and returned to customers. During each of the years ended December 31, 2025 and 2024, we recorded $9 million of amortization related to the excess deferred taxes to income tax provision in our consolidated statements of comprehensive income.

8. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment, net consisted of the following:


	December 31,
(In millions of USD)	2025		2024
Property, plant and equipment
Regulated Operating Subsidiaries:
Property, plant and equipment	$	14,949	$	13,913
Construction work in progress	821		670
Capital equipment	192		160
Other	111		87
ITC Holdings and other	15		14
Total	16,088		14,844
Less: Accumulated depreciation and amortization	(2,892)		(2,715)
Property, plant and equipment, net	$	13,196	$	12,129

Additions to property, plant and equipment and construction work in progress during 2025 and 2024 were due primarily to projects to upgrade or replace existing transmission plant and update grid security to improve the reliability of our transmission systems as well as transmission infrastructure to support generator interconnections and investments that provide regional benefits.

Depreciation and amortization expense on property, plant and equipment was $346 million, $320 million and $300 million for the years ended December 31, 2025, 2024 and 2023, respectively.

Our Regulated Operating Subsidiaries capitalize to property, plant and equipment AFUDC in accordance with FERC regulations. AFUDC represents the composite cost incurred to fund the construction of assets, including interest expense and return on equity. The interest component of AFUDC was a reduction to interest expense of

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$12 million for each of the years ended December 31, 2025 and 2024 and $11 million for the year ended December 31, 2023.

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9. DEBT

Amounts of outstanding debt were classified as debt maturing within one year and long-term debt on the consolidated statements of financial position as follows:


	December 31,
(In millions of USD)	2025		2024
ITC Holdings 6.375% Senior Notes, due September 30, 2036	$	200	$	200
ITC Holdings 5.30% Senior Notes, due July 1, 2043	300		300
ITC Holdings 3.25% Notes, due June 30, 2026 (a)	400		400
ITC Holdings 3.35% Senior Notes, due November 15, 2027	500		500
ITC Holdings 2.95% Senior Notes, due May 14, 2030	700		700
ITC Holdings 4.95% Senior Notes, due September 22, 2027	900		900
ITC Holdings 5.40% Senior Notes, due June 1, 2033	500		500
ITC Holdings 5.65% Senior Notes, due May 9, 2034	400		400
ITC Holdings Commercial Paper Program (a)	237		—
ITCTransmission 6.125% First Mortgage Bonds, Series C, due March 31, 2036	100		100
ITCTransmission 4.625% First Mortgage Bonds, Series E, due August 15, 2043	285		285
ITCTransmission 4.27% First Mortgage Bonds, Series F, due June 10, 2044	100		100
ITCTransmission 4.00% First Mortgage Bonds, Series G, due March 30, 2053	225		225
ITCTransmission 3.30% First Mortgage Bonds, Series H, due August 28, 2049	75		75
ITCTransmission 2.93% First Mortgage Bonds, Series I, due January 14, 2052	20		20
ITCTransmission 2.93% First Mortgage Bonds, Series J, due January 14, 2052	130		130
ITCTransmission 5.11% First Mortgage Bonds, Series K, due January 23, 2029	75		75
ITCTransmission 5.38% First Mortgage Bonds, Series L, due January 23, 2034	75		75
METC 5.64% Senior Secured Notes, due May 6, 2040	50		50
METC 3.98% Senior Secured Notes, due October 26, 2042	75		75
METC 4.19% Senior Secured Notes, due December 15, 2044	150		150
METC 3.90% Senior Secured Notes, due April 26, 2046	200		200
METC 4.55% Senior Secured Notes, Series A, due January 15, 2049	50		50
METC 4.65% Senior Secured Notes, Series B, due July 10, 2049	50		50
METC 3.02% Senior Secured Notes, due October 14, 2055	150		150
METC 2.90% Senior Secured Notes, Series A, due August 3, 2051	75		75
METC 3.05% Senior Secured Notes, Series B, due May 10, 2052	75		75
METC 5.65% Senior Secured Notes, Series A, due November 1, 2028	90		90
METC 5.98% Senior Secured Notes, Series B, due January 16, 2034	85		85
ITC Midwest 6.15% First Mortgage Bonds, Series A, due January 31, 2038	175		175
ITC Midwest 3.50% First Mortgage Bonds, Series E, due January 19, 2027	100		100
ITC Midwest 4.09% First Mortgage Bonds, Series F, due April 30, 2043	100		100
ITC Midwest 3.83% First Mortgage Bonds, Series G, due April 7, 2055	225		225
ITC Midwest 4.16% First Mortgage Bonds, Series H, due April 18, 2047	200		200
ITC Midwest 4.32% First Mortgage Bonds, Series I, due November 1, 2051	175		175
ITC Midwest 3.13% First Mortgage Bonds, Series J, due July 15, 2051	180		180
ITC Midwest 3.87% First Mortgage Bonds, Series K, due October 12, 2027	75		75
ITC Midwest 4.53% First Mortgage Bonds, Series L, due October 12, 2052	75		75
ITC Midwest 4.88% First Mortgage Bonds, Series M, due December 10, 2035	125		125
ITC Midwest 5.25% First Mortgage Bonds, Series N, due December 10, 2043	125		125
ITC Great Plains 4.16% First Mortgage Bonds, Series A, due November 26, 2044	100		100
Revolving Credit Agreement, due April 14, 2028	589		247
Other	2		2
Total principal	8,518		7,939
Unamortized deferred financing fees and discount (b)	(41)		(47)
Unamortized discount related to commercial paper (a)	(1)		—
Total debt	$	8,476	$	7,892

____________________________

(a)As of December 31, 2025 there was $636 million, net of unamortized deferred financing fees and discount, of debt included within debt maturing within one year on the consolidated statements of financial position. At December 31, 2024 there was no debt maturing within one year on the consolidated statements of financial position.

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(b)We recorded $7 million for each of the years ended December 31, 2025 and 2024 and $6 million for the year ended December 31, 2023 to interest expense for the amortization of deferred financing fees and debt discounts.

The annual maturities of debt as of December 31, 2025 are as follows:


(In millions of USD)
2026	$	637
2027	1,575
2028	679
2029	75
2030	700
2031 and thereafter	4,852
Total	$	8,518

ITC Holdings

Senior Unsecured Notes

On May 9, 2024, ITC Holdings completed a debt issuance of $400 million aggregate principal amount of unsecured 5.65% Senior Notes, due May 9, 2034. The 5.65% Senior Notes are redeemable prior to February 9, 2034, in whole or in part and at the option of ITC Holdings, by paying an applicable make whole premium. The net proceeds from this offering, after discount and costs related to the issuance, were used to partially fund the repayment of the $400 million aggregate principal amount of ITC Holdings 3.65% Senior Notes due June 15, 2024 and for general corporate purposes. The Senior Notes were issued under ITC Holdings’ indenture, dated April 18, 2013, between ITC Holdings and Computershare Trust Company, N.A., as successor to Wells Fargo Bank, National Association, as trustee, as supplemented from time to time, including by the Eighth Supplemental Indenture, dated as of May 9, 2024.

Commercial Paper Program

ITC Holdings has an ongoing commercial paper program for the issuance and sale of unsecured commercial paper in an aggregate amount not to exceed $400 million outstanding at any one time. As of December 31, 2025, ITC Holdings had $236 million of commercial paper, net of discount, issued and outstanding under the program, with a weighted average interest rate of 4.02% and weighted average remaining days to maturity of 35 days. The amount outstanding as of December 31, 2025 was classified as debt maturing within one year in the consolidated statements of financial position. As of December 31, 2024, ITC Holdings did not have any commercial paper issued and outstanding under the program. The Company’s revolving credit agreement may be used to repay commercial paper issued pursuant to the commercial paper program.

ITCTransmission

First Mortgage Bonds

On January 23, 2024, ITCTransmission issued an aggregate principal amount of $75 million of 5.11% First Mortgage Bonds, Series K, due January 23, 2029 and an aggregate principal amount of $75 million of 5.38% First Mortgage Bonds, Series L, due January 23, 2034. The proceeds were used to repay existing indebtedness under the revolving credit agreement, to partially fund capital expenditures and for general corporate purposes.

All of ITCTransmission’s First Mortgage Bonds are issued under its First Mortgage and Deed of Trust and secured by a first mortgage lien on substantially all of its real property and tangible personal property.

METC

Senior Secured Notes

On January 14, 2026, METC completed a private offering of Senior Secured Notes totaling an aggregate principal amount of $250 million. The offering consisted of an issuance on January 14, 2026 of $125 million of 5.08% Series A Senior Secured Notes due January 14, 2036 and $125 million of 5.71% Series B Senior Secured Notes due January 14, 2046. The proceeds from the Senior Secured Notes were used to repay

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indebtedness under the revolving credit agreement and intercompany loan agreement, to partially fund capital expenditures and for general corporate purposes.

On November 1, 2023, METC completed a private offering of Senior Secured Notes totaling an aggregate principal amount of $175 million. The offering consisted of an issuance of $90 million on November 1, 2023 of 5.65% Series A Senior Secured Notes due November 1, 2028 and an issuance of $85 million on January 16, 2024 of 5.98% Series B Senior Secured Notes due January 16, 2034. The proceeds from the Senior Secured Notes were used to repay indebtedness under the revolving credit agreement, to partially fund capital expenditures and for general corporate purposes.

All of METC’s Senior Secured Notes are issued under its first mortgage indenture and secured by a first mortgage lien on substantially all of its real property and tangible personal property.

ITC Midwest

First Mortgage Bonds

On December 10, 2024, ITC Midwest issued an aggregate principal amount of $125 million of 4.88% First Mortgage Bonds, Series M, due December 10, 2035 and an aggregate principal amount of $125 million of 5.25% First Mortgage Bonds, Series N, due December 10, 2043. The proceeds were used to repay existing indebtedness under the revolving credit agreement, to partially fund capital expenditures and for general corporate purposes.

All of ITC Midwest’s First Mortgage Bonds were issued under its First Mortgage and Deed of Trust and secured by a first mortgage lien on substantially all of its real property and tangible personal property.

ITC Great Plains

First Mortgage Bonds

On June 24, 2024, ITC Great Plains completed a partial redemption of $50 million of the $150 million aggregate principal amount of 4.16% First Mortgage Bonds, Series A, due November 26, 2044. There was no make-whole premium payment associated with the redemption.

Revolving Credit Agreement

At December 31, 2025, we had the following unguaranteed, unsecured revolving credit facility available and outstanding:


(In millions of USD)	Total Available Capacity (a)		Outstanding Balance (b)		Unused Capacity		Weighted Average Interest Rate on Outstanding Balance (c)		Commitment Fee Rate (d)
ITC Holdings	$	350	$	—	$	350	—	%	0.175	%
ITCTransmission	175		171		4		4.77	%	0.100	%
METC	215		180		35		4.77	%	0.100	%
ITC Midwest	185		173		12		4.77	%	0.100	%
ITC Great Plains	75		65		10		4.77	%	0.100	%
Total	$	1,000	$	589	$	411

____________________________

(a)Represents the current borrowing sublimit. Individual sublimits may be adjusted, subject to certain individual sublimits and the aggregate limit under the revolving credit agreement not to exceed $1 billion.

(b)Included within long-term debt on the consolidated statements of financial position.

(c)Interest charged on borrowings depends on the variable rate structure we elect at the time of each borrowing.

(d)Calculation based on the average daily unused commitments, subject to adjustment based on the borrower’s credit rating.

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Derivative Instruments and Hedging Activities

We use derivative financial instruments to manage our exposure to fluctuations in interest rates. The following derivative instruments qualified for cash flow hedge accounting treatment. The contracts are used to manage interest rate risk associated with forecasted debt issuances at ITC Holdings.


(In millions of USD)	Notional Amount		Weighted Average Fixed Rate		Gain (Loss) on Derivatives (a)		Term (In years)	Effective Date
Outstanding derivative instruments
Interest rate swaps	$	560	3.54	%	$	—	5	Q2 2026
Interest rate swaps	195		3.51	%	—		5	Q3 2027
Settled derivative instruments
U.S. Treasury rate lock contracts	500		3.46	%	4		10	Q2 2023
U.S. Treasury rate lock contracts	300		4.66	%	(3)		5	Q2 2024

____________________________

(a)This amount, recorded net of tax in AOCI, is amortized as a component of interest expense over the term of the derivative instrument as the forecasted transactions affect earnings. See Note 13 for additional information.

10. INCOME TAXES

For the years ended December 31, 2025, 2024 and 2023, our effective tax rates were 23.5%, 23.4% and 25.2%, respectively. Our effective tax rate varied from the statutory federal income tax rate due to differences between the book and tax treatment of various transactions as follows:


	Year Ended December 31,
(In millions of USD)	2025				2024				2023
Income before income taxes	$	678			$	632			$	619

Income tax expense at 21% federal statutory rate	142		21.0	%	133		21.0	%	130		21.0	%
State income tax expense net of federal benefit (a)	32		4.7	%	31		4.9	%	41		6.6	%





Nontaxable or nondeductible items	1		0.1	%	—		—	%	1		0.2	%

Other Adjustments:
AFUDC equity	(7)		(1.0)	%	(7)		(1.1)	%	(7)		(1.1)	%
Amortization of revalued deferred federal income taxes	(9)		(1.3)	%	(9)		(1.4)	%	(9)		(1.5)	%




Total income tax provision	$	159	23.5	%	$	148	23.4	%	$	156	25.2	%

____________________________

(a)Michigan makes up the majority (greater than 50 percent) of the state income tax expense net of federal benefit category. Amounts for the year ended December 31, 2023 include $6 million related to the remeasurement of certain deferred tax balances and NOLs due to the Iowa corporate income tax rate reduction from 8.4% to 7.1%.

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Components of the income tax provision were as follows:


	Year Ended December 31,
(In millions of USD)	2025		2024		2023
Current income tax expense
Federal income tax	$	35	$	48	$	45
State income tax	5		7		6
Total current income tax expense	40		55		51
Deferred income tax expense
Federal income tax	92		69		69
State income tax	27		24		36
Total deferred income tax expense	119		93		105
Total income tax provision	$	159	$	148	$	156

Deferred income tax assets (liabilities) consisted of the following:


	December 31,
(In millions of USD)	2025		2024
Property, plant and equipment	$	(1,704)	$	(1,573)



Goodwill	(148)		(147)


Regulatory liability gross up due to change in federal income tax rate	112		115
Pension and postretirement liabilities	21		21
State income tax NOLs (net of federal benefit)	37		41


Valuation allowance	(1)		(4)


Other, net	21		26
Net deferred income tax liabilities	$	(1,662)	$	(1,521)
Gross deferred income tax liabilities	$	(1,890)	$	(1,752)
Gross deferred income tax assets	229		235
Valuation allowance	(1)		(4)
Net deferred income tax liabilities	$	(1,662)	$	(1,521)

We had state income tax NOLs as of December 31, 2025, which expire in the years 2026 to 2041 or are indefinite. We expect to utilize the majority of these state NOLs prior to their expiration. We believe that it is more likely than not that the benefit from certain state NOL carryforwards will not be realized and have recorded a valuation allowance accordingly.

11. RETIREMENT BENEFITS AND ASSETS HELD IN TRUST

Pension and Postretirement Plan Benefits

We have a qualified defined benefit pension plan (the “retirement plan”) for eligible employees, comprised of a traditional final average pay plan and a cash balance plan. The traditional final average pay plan is noncontributory, covers select employees, and provides retirement benefits based on years of benefit service, average final compensation and age at retirement. The cash balance plan is also noncontributory, covers substantially all employees and provides retirement benefits based on eligible compensation and interest credits. Our funding practice for the retirement plan is generally to fund the annual net pension cost, though we may adjust our funding as necessary based on consideration of federal funding requirements, the funded status of the plan, and other considerations as we deem appropriate. We made contributions to the retirement plan of $4 million in each of 2025 and 2024. We did not contribute to the retirement plan in 2023. We expect to contribute $3 million to the retirement plan in 2026.

We also have two supplemental nonqualified, noncontributory, defined benefit pension plans for selected management employees (the “supplemental benefit plans” and, collectively with the retirement plan, the

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“pension plans”). The supplemental benefit plans provide for benefits that supplement those provided by the retirement plan. The obligations under these supplemental benefit plans are included in the pension benefit obligation calculations below. The investments held in trust for the supplemental benefit plans of $45 million at each of the years ended December 31, 2025 and 2024, are not included in the plan asset amounts presented throughout this footnote, but are included in other assets on our consolidated statements of financial position. We contributed less than $1 million in 2025 and $1 million in each of 2024 and 2023 to the supplemental benefits plan.

We provide certain postretirement health care, dental and life insurance benefits for eligible employees (the “postretirement benefit plan”). We did not contribute to the postretirement benefit plan in 2025 and 2024. We contributed $1 million to the postretirement benefit plan in 2023. We do not expect to contribute to the postretirement benefit plan in 2026.

Net periodic benefit cost/(credit) by component for the pension plans and postretirement benefit plan was as follows:


	Pension Plans						Postretirement Benefit Plan
	Year Ended December 31,						Year Ended December 31,
(In millions of USD)	2025		2024		2023		2025		2024		2023
Service cost	$	8	$	8	$	7	$	7	$	7	$	7
Interest cost	7		7		6		6		5		5
Expected return on plan assets	(8)		(8)		(6)		(8)		(8)		(6)
Amortization of prior service credit	—		—		—		—		—		(1)
Amortization of unrecognized loss/(gain)	—		—		—		(5)		(5)		(4)
Net periodic benefit cost/(credit)	$	7	$	7	$	7	$	—	$	(1)	$	1

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The following table reconciles the obligations, assets and funded status of the pension plans and postretirement benefit plan as well as the presentation of the funded status of the plans on the consolidated statements of financial position:


	Pension Plans				Postretirement Benefit Plan
	December 31,				December 31,
(In millions of USD)	2025		2024		2025		2024
Change in Benefit Obligation:
Beginning projected benefit obligation / accumulated postretirement benefit obligation	$	(139)	$	(140)	$	(110)	$	(97)
Service cost	(8)		(8)		(7)		(7)
Interest cost	(7)		(7)		(6)		(5)

Actuarial net gain/(loss)	3		6		(6)		(3)
Benefits paid	10		8		3		3
Settlements	—		2		—		—
Plan participants’ contributions	—		—		(1)		(1)
Ending projected benefit obligation / accumulated postretirement benefit obligation	(141)		(139)		(127)		(110)
Change in Plan Assets:
Beginning plan assets at fair value	114		105		155		141
Actual return on plan assets	16		9		19		16
Employer contributions	4		4		—		—

Benefits paid	(6)		(4)		(3)		(3)
Plan participants’ contributions	—		—		1		1
Ending plan assets at fair value	128		114		172		155
Funded status, (underfunded)/overfunded	$	(13)	$	(25)	$	45	$	45
Accumulated benefit obligation:
Retirement plan	$	(107)	$	(92)	N/A		N/A
Supplemental benefit plans	(30)		(42)		N/A		N/A
Total accumulated benefit obligation	$	(137)	$	(134)	N/A		N/A
Amounts recorded as:
Funded Status:
Accrued pension and postretirement liabilities	$	(27)	$	(39)	$	—	$	—
Other non-current assets	18		19		45		45
Other current liabilities	(4)		(5)		—		—
Total	$	(13)	$	(25)	$	45	$	45
Unrecognized Amounts in Non-Current Regulatory Assets:
Net actuarial loss	$	1	$	8	$	—	$	—

Total	$	1	$	8	$	—	$	—
Unrecognized Amounts in Non-Current Regulatory Liabilities:
Net actuarial (gain)	$	(11)	$	(8)	$	(61)	$	(61)
Net prior service cost/(credit)	—		1		—		—
Total	$	(11)	$	(7)	$	(61)	$	(61)

The unrecognized amounts that otherwise would have been charged and/or credited to AOCI in accordance with the GAAP guidance on accounting for retirement benefits are recorded as a regulatory asset or regulatory liability on our consolidated statements of financial position, as discussed in Note 7. The amounts recorded as a

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regulatory asset or regulatory liability represent a net periodic benefit cost or credit to be recognized in our operating income in future periods. Our measurement of the accumulated benefit obligation for the postretirement benefit plan reflects anticipated future receipts of subsidies under the Medicare Prescription Drug, Improvement and Modernization Act of 2003, which we have applied for beginning in 2023.

The net actuarial gain for the year ended December 31, 2025 within the change in benefit obligation for the pension plans is primarily the result of an increase of $12 million related to demographic experience, partially offset by losses of $9 million due to decreases in the discount rates and increase in the interest credit rating. The net actuarial gain for the year ended December 31, 2024 within the change in benefit obligation for the pension plans is primarily the result of increases in the discount rates. The net actuarial loss for the year ended December 31, 2025 within the change in benefit obligation for the postretirement benefit plan is due to impacts of $3 million for demographic assumption changes and experience and $3 million due to financial assumptions changes, primarily due to the decrease in the discount rate.

The combined projected benefit obligation and fair value of plan assets for those plans in which the projected benefit obligation is in excess of the fair value of plan assets are as follows:


	Pension Plans
	December 31,
(In millions of USD)	2025		2024
Projected benefit obligation	$	(31)	$	(44)
Fair value of plan assets (a)	—		—

____________________________

(a)The investments held in trust for our supplemental benefit plans are not included in the plan asset amounts presented herein, but are included in other assets on our consolidated statements of financial position.

The combined accumulated benefit obligation and fair value of plan assets for those plans in which the accumulated benefit obligation is in excess of the fair value of plan assets are as follows:


	Pension Plans
	December 31,
(In millions of USD)	2025		2024
Accumulated benefit obligation	$	(30)	$	(42)
Fair value of plan assets (a)	—		—

____________________________

Actuarial assumptions used to determine the net periodic benefit obligations for the pension plans and postretirement benefit plan are as follows:


	Pension Plans			Postretirement Benefit Plan
	December 31,			December 31,
	2025	2024	2023	2025	2024	2023
Weighted average discount rate	5.34%	5.66%	5.19%	5.72%	5.86%	5.30%
Weighted average interest crediting rate	5.00%	4.50%	4.50%	N/A	N/A	N/A
Annual rate of salary increases	4.50%	4.50%	4.50%	4.50%	4.50%	4.50%
Health care cost trend rate	N/A	N/A	N/A	6.75%	7.00%	6.50%
Ultimate health care cost trend rate	N/A	N/A	N/A	5.00%	5.00%	5.00%
Year that the ultimate trend rate is reached	N/A	N/A	N/A	2033	2033	2030
Annual rate of increase in dental benefit costs	N/A	N/A	N/A	4.50%	4.50%	4.50%

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Actuarial assumptions used to determine the benefit cost for the pension plans and postretirement benefit plan are as follows:


	Pension Plans			Postretirement Benefit Plan
	Year Ended December 31,			Year Ended December 31,
	2025	2024	2023	2025	2024	2023
Weighted average discount rate — service cost	5.80%	5.26%	5.59%	6.04%	5.48%	5.83%
Weighted average discount rate — interest cost	5.40%	5.10%	5.40%	5.62%	5.17%	5.51%
Weighted average interest crediting rate	4.50%	4.50%	4.00%	N/A	N/A	N/A
Annual rate of salary increases	4.50%	4.50%	4.00%	4.50%	4.50%	4.00%
Health care cost trend rate	N/A	N/A	N/A	7.00%	6.50%	6.75%
Ultimate health care cost trend rate	N/A	N/A	N/A	5.00%	5.00%	5.00%
Year that the ultimate trend rate is reached	N/A	N/A	N/A	2033	2030	2030
Expected long-term rate of return on plan assets	7.00%	7.30%	6.90%	5.20%	5.50%	5.20%

At December 31, 2025, the projected benefit payments for the pension plans and postretirement benefit plan (including prescription drug benefits) calculated using the same assumptions as those used to calculate the benefit obligations described above are as follows:


(In millions of USD)	Pension Plans		Postretirement Benefit Plan
2026	$	10	$	3
2027	10		4
2028	10		4
2029	13		5
2030	14		5
2031 through 2035	65		37

Investment Objectives and Fair Value Measurement

The general investment objectives of the retirement plan and postretirement benefit plan include maximizing the return within reasonable and prudent levels of risk and controlling administrative and management costs. Investment decisions are made by our retirement benefits board as delegated by our board of directors. Equity investments may include various types of U.S. and international equity securities, such as large-cap, mid-cap, and small-cap stocks. Fixed income investments may include cash and short-term instruments, U.S. Government securities, corporate bonds, mortgages, and other fixed income investments. No investments are prohibited for use in the retirement plan or postretirement benefit plan, including derivatives, but our exposure to derivatives currently is not material. We intend that the long-term capital growth of the retirement and postretirement benefit plans, together with employer contributions, will provide for the payment of the benefit obligations.

As of December 31, 2025 and 2024, the plan assets of the retirement plan and postretirement benefit plan consisted of the following assets by category:


	Target Allocation		Pension Plans				Postretirement Benefit Plan
Asset Category	2025		2025		2024		2025		2024
Fixed income securities	50	%	50	%	51	%	50	%	50	%
Equity securities	50	%	50	%	49	%	50	%	50	%
Total	100	%	100	%	100	%	100	%	100	%

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We determine our expected long-term rate of return on plan assets based on the current and expected target allocations of the retirement plan and postretirement benefit plan investments and considering historical and expected long-term rates of return on comparable fixed income investments and equity investments.

We classify the plan assets related to our retirement plan and postretirement benefit plan based on the three-tier fair value hierarchy as discussed in Note 12, except for certain investments measured using NAV as a practical expedient for fair value. The following are descriptions of our investments held by the retirement plan and postretirement benefit plan trusts as well as the valuation methods and assumptions we use to estimate their fair values:

•Mutual funds: The mutual funds consist primarily of publicly traded mutual funds recorded at fair value based on observable trades for identical securities quoted in an active market. Investments in mutual funds sponsored by a registered investment company are valued based on exchange listed prices and are classified as Level 1 of the fair value hierarchy.

•Collective Investment Trust: The collective investment trust consists primarily of fixed income securities and is recorded at NAV which is provided by the fund sponsor. The collective investment trust investments offer daily liquidity. There are no unfunded commitments related to these funds. Investments in the collective investment trust are valued based on the NAV of units owned, which is based on the current fair value of the funds’ underlying assets. These investments are not classified within the hierarchy and instead are presented beneath the hierarchy given they are valued at NAV as a practical expedient.

For the years ended December 31, 2025 and 2024, the fair value of retirement plan and postretirement benefit plan assets were as follows:


	Pension Plans				Postretirement Benefit Plan
	December 31,				December 31,
(In millions of USD)	2025		2024		2025		2024
Financial assets categorized as Level 1:
Mutual funds — U.S. equity securities	$	51	$	45	$	82	$	74
Mutual funds — international equity securities	13		11		4		3
Mutual funds — fixed income securities	38		58		79		78
Total investments in the fair value hierarchy	102		114		165		155
Financial assets measured at NAV:
Collective investment trust — fixed income securities	26		—		7		—
Total investments	$	128	$	114	$	172	$	155

Defined Contribution Plan

We also sponsor a defined contribution retirement savings plan. Participation in this plan is available to substantially all employees. We match employee contributions up to certain predefined limits based upon eligible compensation and the employee’s contribution rate. The cost of this plan was $8 million for the year ended December 31, 2025 and $7 million for each of the years ended December 31, 2024 and 2023.

12. FAIR VALUE MEASUREMENTS

The measurement of fair value is based on a three-tier hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. Changes in economic conditions or model-based valuation techniques may require the transfer of financial instruments from one fair value level to another. In such instances, the transfer is reported at the beginning of the reporting period. For the years ended December 31, 2025 and 2024, there were no transfers between levels.

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Our assets and liabilities measured at fair value subject to the three-tier hierarchy at December 31, 2025, were as follows:


	Fair Value Measurements at Reporting Date Using
	Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
(In millions of USD)	(Level 1)		(Level 2)		(Level 3)
Financial assets measured on a recurring basis:
Cash and cash equivalents	$	3	$	—	$	—
Mutual funds — fixed income securities	41		—		—
Mutual funds — equity securities	15		—		—
Interest rate swap derivatives	—		3		—
Financial liabilities measured on a recurring basis:
Interest rate swap derivatives	—		4		—
Total	$	59	$	(1)	$	—

Our assets measured at fair value subject to the three-tier hierarchy at December 31, 2024, were as follows:


	Fair Value Measurements at Reporting Date Using
	Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
(In millions of USD)	(Level 1)		(Level 2)		(Level 3)
Financial assets measured on a recurring basis:

Cash and cash equivalents	$	1	$	—	$	—
Mutual funds — fixed income securities	42		—		—
Mutual funds — equity securities	15		—		—
Interest rate swap derivatives	—		4		—



Total	$	58	$	4	$	—

The investments recorded within cash and cash equivalents and other long-term assets include investments held in a trust associated with our supplemental benefit plans described in Note 11 and certain deferred compensation plan investments. The mutual funds we own are publicly traded and are recorded at fair value based on observable trades for identical securities in an active market. Changes in the observed trading prices and liquidity of money market funds are monitored as additional support for determining fair value. Gains and losses for all mutual fund investments are recorded in other expenses (income), net in the consolidated statements of comprehensive income.

The assets and liabilities related to derivatives consist of interest rate swaps as discussed in Note 9. The fair value of these derivatives is determined based on a discounted cash flow method using the Secured Overnight Financing Rate, which are observable at commonly quoted intervals.

We also held non-financial assets that are required to be measured at fair value on a non-recurring basis. These consist of goodwill and intangible assets. We did not record any impairment charges on long-lived assets and no other significant events occurred requiring non-financial assets and liabilities to be measured at fair value (subsequent to initial recognition) during the years ended December 31, 2025 and 2024.

Fair Value of Financial Assets and Liabilities

Fixed Rate Debt

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term debt and debt maturing within one year, net of discount and deferred financing fees and excluding borrowings on the revolving credit agreement and commercial paper, was $7,651 million and $7,645 million at December 31, 2025 and 2024, respectively.

Revolving Credit Agreement

Other Financial Instruments

The carrying value of other financial instruments including cash and cash equivalents and commercial paper, approximates their fair value due to the short-term nature of these instruments.

13. STOCKHOLDER'S EQUITY

Accumulated Other Comprehensive Income (Loss)

The following table provides the components of changes in AOCI:


	Year Ended December 31,
(In millions of USD)	2025		2024		2023
Balance at the beginning of period	$	28	$	29	$	27


Derivative instruments
Reclassification of net gain relating to interest rate cash flow hedges from AOCI to earnings (net of tax of $(1), $(1) and $—, respectively) (a)	(4)		(2)		(1)

(Loss) gain on interest rate swaps relating to interest rate cash flow hedges (net of tax of $(1), $— and $1, respectively)	(3)		1		3




Total other comprehensive (loss) income, net of tax	(7)		(1)		2
Balance at the end of period	$	21	$	28	$	29

____________________________

(a)The reclassification of the net gain relating to interest rate cash flow hedges is reported in interest expense, net in the consolidated statements of comprehensive income on a pre-tax basis.

The amount of net gain relating to interest rate cash flow hedges to be reclassified from AOCI to earnings for the 12-month period ending December 31, 2026 is expected to be approximately $6 million (net of tax of $2 million).

14. SHARE-BASED COMPENSATION

We recorded share-based compensation costs as follows:


	Year Ended December 31,
(In millions of USD)	2025		2024		2023
Operation and maintenance expenses	$	2	$	2	$	2
General and administrative expenses	35		13		13
Amounts capitalized to property, plant and equipment	12		12		8
Total share-based compensation costs	$	49	$	27	$	23
Total tax benefit recognized in the consolidated statements of comprehensive income	$	13	$	7	$	6

Long-Term Incentive Plans

Performance-Based Units

The PBUs are measured at fair value at the end of each reporting period, which will fluctuate based on the price of Fortis common stock and the level of achievement of the financial performance criteria, including a

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market condition and a performance condition. The payout may range from 0% - 200% of the target award, depending on actual performance relative to the performance criteria. The PBUs earn dividend equivalents which are also re-measured consistent with the target award and settled in cash at the end of the vesting period.

The following table shows the changes in PBUs during the year ended December 31, 2025:


			Number of
			Performance
			Based Units
PBUs at December 31, 2024			898,994
Granted			383,382
Vested and paid out			(260,895)
Forfeited			(24,366)
PBUs at December 31, 2025			997,115

The following table presents the classification on the consolidated statements of financial position of obligations related to outstanding PBUs not yet settled:


	December 31,
(In millions of USD)	2025		2024
Accrued compensation	$	24	$	10
Other long-term liabilities	26		17
Total	$	50	$	27

The aggregate fair value of PBUs as of December 31, 2025 and 2024 was $68 million and $37 million, respectively. At December 31, 2025, $18 million of total unrecognized compensation cost related to PBUs not yet vested is expected to be recognized over the remaining weighted average period of 1.8 years.

Service-Based Units

The SBUs are measured at fair value at the end of each reporting period, which will fluctuate based on the price of Fortis common stock. The SBUs earn dividend equivalents which are also re-measured based on the price of Fortis common stock and settled in cash at the end of the vesting period.

The following table shows the changes in SBUs during the year ended December 31, 2025:


			Number of
			Service
			Based Units
SBUs at December 31, 2024			711,973
Granted			304,443
Vested and paid out			(197,988)
Forfeited			(24,366)
SBUs at December 31, 2025			794,062

The following table presents the classification on the consolidated statements of financial position of obligations related to outstanding SBUs not yet settled:


	December 31,
(In millions of USD)	2025		2024
Accrued compensation	$	12	$	9
Other long-term liabilities	17		13
Total	$	29	$	22

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The aggregate fair value of SBUs as of December 31, 2025 and 2024 was $41 million and $31 million, respectively. At December 31, 2025, $12 million of the total unrecognized compensation cost related to SBUs not yet vested is expected to be recognized over the remaining weighted average period of 1.8 years.

15. JOINTLY OWNED UTILITY PLANT/COORDINATED SERVICES

As of December 31, 2025, the following summarizes our Regulated Operating Subsidiaries’ jointly-owned transmission assets:


(In millions of USD except for ownership interest)	Ownership Interest		Property, Plant and Equipment		Accumulated Depreciation		Construction Work in Progress
Huntley Wilmarth (a)	50.0	%	$	57	$	6	$	—
Cardinal Hickory Creek (b)	91.0	%	305		13		—
Other (c)
ITCTransmission	49.6	%	45		19		—
METC	various		98		45		—
ITC Midwest	various		98		22		2
ITC Great Plains	49.0	%	33		6		—

____________________________

(a)Jointly owned between ITC Midwest and Northern States Power Company.

(b)Jointly owned between ITC Midwest and Dairyland Power Cooperative.

(c)Jointly owned with various parties.

16. RELATED PARTY TRANSACTIONS

We may incur charges from Fortis and other affiliates of Fortis that are not subsidiaries of ITC Holdings (“Fortis and Fortis affiliates”) for general corporate expenses incurred. In addition, we may perform additional services for, or receive additional services from, Fortis and such subsidiaries. These transactions are in the normal course of business and payments for these services are settled through accounts receivable and accounts payable, as necessary.

Periodically, we pay dividends to ITC Investment Holdings as shown in the consolidated statements of cash flows. On February 2, 2026, our Board of Directors approved a $72 million dividend to ITC Investment Holdings that is expected to be paid on February 27, 2026.

We are organized as a corporation for tax purposes and subject to a tax sharing agreement as a wholly-owned subsidiary of ITC Investment Holdings. Additionally, we record income taxes based on our separate company tax position and make or receive tax-related payments with ITC Investment Holdings. See Note 18 for information on income tax payments made to ITC Investment Holdings.


	December 31,
(In millions of USD)	2025		2024
Statements of financial position activity:
Accounts receivable from Fortis and Fortis affiliates	$	1	$	1

Net income tax receivable from ITC Investment Holdings (a)	2		—
Net income tax payable to ITC Investment Holdings (b)	—		7

__________________________

(a)Recorded in prepaid and other current assets on the consolidated statements of financial position.

(b)Recorded in accrued taxes on the consolidated statements of financial position.

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	Year Ended December 31,
(In millions of USD)	2025		2024		2023
Statements of comprehensive income activity:
Billed from Fortis and Fortis affiliates (a)	$	14	$	13	$	12
Billed to Fortis and Fortis affiliates (b)	3		4		3

____________________________

(a)Recorded in general and administrative expenses in the consolidated statements of comprehensive income.

(b)Recorded as an offset to general and administrative expenses in the consolidated statements of comprehensive income.

17. COMMITMENTS AND CONTINGENT LIABILITIES

Environmental Matters

We are subject to federal, state and local environmental laws and regulations, which impose limitations on the discharge of pollutants into the environment, require reporting of emissions from certain equipment, establish standards for the management, treatment, storage, transportation and disposal of hazardous materials and of solid and hazardous wastes, and impose obligations to investigate and remediate contamination in certain circumstances. Liabilities relating to investigation and remediation of contamination, as well as other liabilities concerning hazardous materials or contamination, such as claims for personal injury or property damage, may arise at many locations, including formerly owned or operated properties and sites where wastes have been treated or disposed of, as well as properties currently owned or operated by us. Such liabilities may arise even where the contamination does not result from noncompliance with applicable environmental laws. Under some environmental laws, such liabilities may also be joint and several, meaning that a party can be held responsible for more than its share of the liability involved, or even the entire share. Although environmental requirements generally have become more stringent and compliance with those requirements more expensive, we are not aware of any specific developments that would increase our costs for such compliance in a manner that would be expected to have a material adverse effect on our financial condition, results of operations or liquidity.

Our assets and operations also involve the use of materials classified as hazardous, toxic or otherwise dangerous. Some of the properties that we own or operate have been used for many years and include older facilities and equipment that may be more likely than newer ones to contain or be made from such materials. Some of these properties include above ground or underground storage tanks and associated piping. Some of them also include large electrical equipment filled with mineral oil, which may contain or previously have contained polychlorinated biphenyls. Some of our facilities and electrical equipment may also contain asbestos containing materials. Our facilities and equipment are often situated close to or on property owned by others so that, if they are the source of contamination, the property of others may be affected. For example, above ground and underground transmission lines sometimes traverse properties that we do not own and transmission assets that we own or operate are sometimes commingled at our transmission stations with distribution assets owned or operated by our transmission customers.

Some properties in which we have an ownership interest or at which we operate are, or are suspected of being, affected by environmental contamination. We are not aware of any pending or threatened claims against us with respect to environmental contamination relating to these properties, or of any investigation or remediation of contamination at these properties, that entail costs likely to materially affect us. Some facilities and properties are located near environmentally sensitive areas, including wetlands and habitat for threatened and endangered species.

Litigation

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Rate of Return on Equity Complaints

Two complaints were filed with the FERC by combinations of consumer advocates, consumer groups, municipal parties and other parties challenging the base ROE in MISO. The complaints were filed under Section 206 of the FPA requesting that the FERC find the MISO regional base ROE rate (the “base ROE”) for all MISO TOs, including our MISO Regulated Operating Subsidiaries, to no longer be just and reasonable.

Initial Complaint

On November 12, 2013, the Association of Businesses Advocating Tariff Equity, Coalition of MISO Transmission Customers, Illinois Industrial Energy Consumers, Indiana Industrial Energy Consumers, Inc., Minnesota Large Industrial Group and Wisconsin Industrial Energy Group (collectively, the “complainants”) filed the Initial Complaint with the FERC. The complainants sought a FERC order to reduce the base ROE used in the formula transmission rates for our MISO Regulated Operating Subsidiaries to 9.15%, reducing the equity component of our capital structure and terminating the ROE adders approved for certain MISO Regulated Operating Subsidiaries. The FERC set the base ROE for hearing and settlement procedures, while denying all other aspects of the Initial Complaint. The ROE collected through the MISO Regulated Operating Subsidiaries’ rates during the period November 12, 2013 through September 27, 2016 consisted of a base ROE of 12.38% plus applicable incentive adders.

Second Complaint

On February 12, 2015, the Second Complaint was filed with the FERC by Arkansas Electric Cooperative Corporation, Mississippi Delta Energy Agency, Clarksdale Public Utilities Commission, Public Service Commission of Yazoo City and Hoosier Energy Rural Electric Cooperative, Inc., seeking a FERC order to reduce the base ROE used in the formula transmission rates of our MISO Regulated Operating Subsidiaries to 8.67%, with an effective date of February 12, 2015.

On June 30, 2016, the presiding administrative law judge issued an initial decision that recommended a base ROE of 9.70% for the refund period from February 12, 2015 through May 11, 2016, with a maximum ROE of 10.68%, which also would be applicable going forward from the date of a final FERC order. The Second Complaint was dismissed as a result of an order issued by the FERC on November 21, 2019 and the dismissal of the complaint was reaffirmed in the May 2020 Order.

Previous FERC Orders

Since the filing of the Initial Complaint, the FERC issued three separate orders in these proceedings resulting in multiple revisions to the base ROE and refund settlements. The MISO TOs, along with our MISO Regulated Operating Subsidiaries, and various other parties have challenged certain aspects of these orders through requests for rehearing. In the May 2020 Order, the FERC determined that a methodology using three financial models should be used to determine the base ROE. By applying the new methodology, the FERC determined that the base ROE for the Initial Complaint should be 10.02% and the top of the range of reasonableness for that period should be 12.62%. The FERC determined that this base ROE should apply during the first refund period of November 12, 2013 to February 11, 2015 and from the date of the order issued by the FERC on September 28, 2016 prospectively. The FERC ordered refunds to be made in accordance with the May 2020 Order. Refund settlements were finalized in 2022.

August 2022 D.C. Circuit Court Decision

On August 9, 2022, in response to appeals of the FERC's orders on the MISO ROE Complaints, the D.C. Circuit Court issued an opinion that rejected the FERC’s use of a risk premium model in the methodology used to determine the revised base ROE for MISO TOs. The D.C. Circuit Court decision vacated the FERC’s orders on the MISO ROE Complaints, dismissed the remaining outstanding appeals of these orders and remanded the matter to the FERC for further proceedings.

October 2024 Order

On October 17, 2024, in response to the August 2022 D.C. Circuit Court decision, the FERC issued the October 2024 Order that revised the methodology used to determine base ROE put forth in the May 2020 Order. In this order, the FERC removed the use of the risk premium model from the calculation, while maintaining other modifications to the methodology as described in previous orders on the MISO ROE Complaints. By applying the revised methodology, the FERC determined that the base ROE for the Initial

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Complaint should be 9.98% for all MISO TOs, including our MISO Regulated Operating Subsidiaries, and the top of the range of reasonableness for that period should be 12.58%. The FERC determined that this base ROE should apply during the first refund period of November 12, 2013 to February 11, 2015 and from the date of the order issued by the FERC on September 28, 2016 prospectively. The FERC ordered refunds to be made in accordance with the order by December 1, 2025. The FERC also reaffirmed its previous finding that no refunds would be ordered on the Second Complaint. Certain MISO TOs, including us, filed a request for rehearing on November 18, 2024 and filed an appeal of the order with the D.C. Circuit Court on January 31, 2025. The request for rehearing and appeal primarily focused on the prospective refund period and the related interest. On March 25, 2025, the FERC issued an order addressing requests for rehearing that made no changes to the October 2024 Order, including the required refunds from September 28, 2016 to the October 2024 Order. The FERC further rejected the MISO TOs’ request that the FERC decline to award interest on any refunds that it ordered the MISO TOs to pay. On August 14, 2025, the MISO TOs filed a petitioner brief with the D.C. Circuit Court in the consolidated appeal challenging the FERC’s orders on the matters of the duration of the refund period and the failure of FERC to directly dismiss the second complaint as unlawful. Timing of a decision on the appeal is unknown. On September 22, 2025, MISO and the MISO TOs requested an extension of the refund resettlement period until June 30, 2026. On November 6, 2025, the FERC partially approved the request for extension of the refund resettlement period until May 1, 2026 and we are working with MISO to determine the resettlement schedule for remaining refunds.

During 2025, we made refund payments of $21 million in accordance with the refund provisions of the order. As of December 31, 2025 and 2024, the aggregate refund liability in current regulatory liabilities was $7 million and $27 million, respectively, and included interest of $2 million and $6 million, respectively.

See Note 6 for a summary of our authorized ROE, which is composed of our base ROE and incentive adders for transmission rates.

Purchase Obligations

At December 31, 2025, we had purchase obligations of $300 million representing commitments for materials, services and equipment that had not been received as of December 31, 2025, primarily for construction and maintenance projects for which we have an executed contract. Of these purchase obligations, $243 million is expected to be paid in 2026, with the majority of the items related to materials and equipment that have long production lead times.

Other Commitments

METC

Amended and Restated Easement Agreement. Under the Easement Agreement, Consumers Energy provides METC with an easement to the land on which a majority of METC’s transmission towers, poles, lines and other transmission facilities used to transmit electricity for Consumers Energy and others are located. The term of the Easement Agreement runs through December 31, 2050 and is subject to 10 automatic 50-year renewals thereafter unless METC gives notice of nonrenewal at least one year in advance. METC pays Consumers Energy $10 million in annual rent per year for the easement and also pays for any rentals, property, taxes, and other fees related to the property covered by the Easement Agreement. Payments to Consumers Energy under the Easement Agreement are charged to operation and maintenance expense in our consolidated statements of comprehensive income.

ITC Midwest

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ITC Great Plains

Concentration of Credit Risk

Our credit risk is primarily with DTE Electric, Consumers Energy and IP&L, which were responsible for approximately 23.0%, 22.4% and 21.7%, respectively, or $403 million, $392 million and $381 million, respectively, of our consolidated billed revenues for the year ended December 31, 2025. This portion of total billed revenues of DTE Electric, Consumers Energy and IP&L include the net refund of 2023 revenue accruals and deferrals and exclude any amounts for the 2025 revenue accruals and deferrals that were included in our 2025 operating revenues but will not be billed to our customers until 2027. Under DTE Electric’s and Consumers Energy’s current rate structure, DTE Electric and Consumers Energy include in their retail rates the actual cost of transmission services provided by ITCTransmission and METC, respectively, in their billings to their customers, effectively passing through to end-use consumers the total cost of transmission service. IP&L currently includes in their retail rates an allowance for transmission services provided by ITC Midwest in their billings to their customers. However, any financial difficulties experienced by DTE Electric, Consumers Energy or IP&L may affect their ability to make payments for transmission service to ITCTransmission, METC, and ITC Midwest, which could negatively impact our business. MISO, as our MISO Regulated Operating Subsidiaries’ billing agent, bills DTE Electric, Consumers Energy, IP&L and other customers on a monthly basis and collects fees for the use of the MISO Regulated Operating Subsidiaries’ transmission systems. SPP is the billing agent for ITC Great Plains and bills transmission customers for the use of ITC Great Plains transmission systems. MISO and SPP have implemented strict credit policies for its members’ customers, which include customers using our transmission systems. Specifically, MISO and SPP require a letter of credit or cash deposit equal to the credit exposure, which is determined by a credit scoring model and other factors, from any customer using a member’s transmission system.

18. SUPPLEMENTAL FINANCIAL INFORMATION

Reconciliation of Cash, Cash Equivalents and Restricted Cash

The following table provides a reconciliation of cash, cash equivalents and restricted cash reported on the consolidated statements of financial position that sum to the total of the same such amounts shown in the consolidated statements of cash flows:


	December 31,
(In millions of USD)	2025		2024		2023
Cash and cash equivalents	$	13	$	19	$	328
Restricted cash included in other non-current assets	26		8		5
Total cash, cash equivalents and restricted cash	$	39	$	27	$	333

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Supplementary Cash Flows Information


	Year Ended December 31,
(In millions of USD)	2025		2024		2023

Interest paid (net of interest capitalized)	$	370	$	340	$	296
Income taxes paid net of refunds:
Federal income taxes paid to ITC Investment Holdings	43		47		42
Michigan income taxes paid to ITC Investment Holdings	5		6		7
Income taxes paid directly to various state jurisdictions	2		1		—
Total income taxes paid	50		54		49
Non-cash investing and financing activities:
Additions to property, plant and equipment (a)	155		153		130
Allowance for equity funds used during construction	44		44		43

Other	7		—		1

____________________________

(a)Amounts consist of current and accrued liabilities for construction, labor, materials and other costs that have not been included in investing activities. These amounts have not been paid for as of December 31, 2025, 2024 or 2023, respectively, but will be or have been included as a cash outflow from investing activities for expenditures for property, plant and equipment when paid.

19. SEGMENT INFORMATION

We identify reportable segments based on factors including the regulatory environment of our subsidiaries and the business activities performed to earn revenues and incur expenses.

Regulated Operating Subsidiaries

We aggregate our Regulated Operating Subsidiaries into one reportable operating segment based on their similar regulatory environment and economic characteristics, among other factors. They are engaged in the transmission of electricity within the United States, earn revenues from the same types of customers and are regulated by the FERC.

ITC Holdings and Other

Information below for ITC Holdings and Other consists primarily of a holding company whose activities include debt financings and general corporate activities. The other subsidiaries of ITC Holdings, excluding the Regulated Operating Subsidiaries, do not have significant operations.

Chief Operating Decision Maker and Use of Net Income Measure

ITC Holdings’ CODM is the Chief Executive Officer, who allocates resources to, and assesses the performance of, ITC Holdings and its Regulated Operating Subsidiaries. The CODM monitors segment performance primarily based on a comparison of actual capital spending, including accrued amounts, and net income relative to budget and uses those metrics to identify opportunities to adjust operations or reallocate resources to achieve corporate objectives.

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	Regulated
	Operating		ITC Holdings		Reconciliations/
2025	Subsidiaries		and Other		Eliminations		Total
(In millions of USD)
Operating revenues	$	1,824	$	1	$	(39)	$	1,786
Depreciation and amortization	349		—		—		349
Interest expense, net	184		181		(1)		364
Other segment items (a)	397		36		(38)		395
Income (loss) before income taxes	894		(216)		—		678
Income tax provision (benefit)	215		(56)		—		159
Subsidiary net earnings	—		679		(679)		—
Net income	679		519		(679)		519
Property, plant and equipment, net	13,189		7		—		13,196
Goodwill	950		—		—		950
Total assets (b)	14,680		7,761		(7,607)		14,834
Capital expenditures	1,324		1		(10)		1,315


	Regulated
	Operating		ITC Holdings		Reconciliations/
2024	Subsidiaries		and Other		Eliminations		Total
(In millions of USD)
Operating revenues	$	1,662	$	—	$	(37)	$	1,625
Depreciation and amortization	326		—		—		326
Interest expense, net	173		175		—		348
Other segment items (a)	357		(1)		(37)		319
Income (loss) before income taxes	806		(174)		—		632
Income tax provision (benefit)	194		(46)		—		148
Subsidiary net earnings	—		612		(612)		—
Net income	612		484		(612)		484
Property, plant and equipment, net	12,122		7		—		12,129
Goodwill	950		—		—		950
Total assets (b)	13,556		7,135		(6,970)		13,721
Capital expenditures	1,072		—		(10)		1,062

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	Regulated
	Operating		ITC Holdings		Reconciliations/
2023	Subsidiaries		and Other		Eliminations		Total
(In millions of USD)
Operating revenues	$	1,581	$	1	$	(37)	$	1,545
Depreciation and amortization	307		—		—		307
Interest expense, net	154		161		—		315
Other segment items (a)	344		(3)		(37)		304
Income (loss) before income taxes	776		(157)		—		619
Income tax provision (benefit)	184		(28)		—		156
Subsidiary net earnings	—		592		(592)		—
Net income	592		463		(592)		463
Property, plant and equipment, net	11,267		7		—		11,274
Goodwill	950		—		—		950
Total assets (b)	12,664		6,988		(6,528)		13,124
Capital expenditures	824		—		(6)		818

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(a)Other segment items includes taxes other than income taxes, general and administrative expense, operation and maintenance expense, allowance for equity funds used during construction and other expense and income items.

(b)Reconciliation of total assets results primarily from differences in the netting of deferred tax assets and liabilities in our segments as compared to the classification in our consolidated statements of financial position.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.

None.

ITEM 9A. CONTROLS AND PROCEDURES.

Management’s Report on Internal Control Over Financial Reporting is included in Item 8. of this Form 10-K.

Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to provide reasonable assurance that material information required to be disclosed in our reports that we file or submit under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required financial disclosure. In designing and evaluating the disclosure controls and procedures, management recognized that a control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, with a company have been detected.

As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 of the Exchange Act. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective, at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

There have been no changes in our internal control over financial reporting during the quarter ended December 31, 2025 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION.

None.

ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS.

Not Applicable.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.

DIRECTORS

Our Bylaws provide for the election of directors at each annual meeting of shareholders. Each director serves until the next annual meeting and until his or her successor is elected and qualified, or until his or her resignation or removal.

The Board must consist of the Chief Executive Officer of the Company (Ms. Apsey), a minority of representatives of Fortis (Mr. Hutchens and Ms. Perry) and a majority of directors who are independent of Fortis. All directors must be independent of any “market participant” in MISO and SPP and a majority of the directors must be “independent” as defined in the Shareholders Agreement. See “Item 13. Certain Relationships And Related Transactions, And Director Independence — Director Independence.”

Linda H. Apsey, 56. Ms. Apsey was named Chief Executive Officer of the Company in July 2024. Ms. Apsey was previously President and Chief Executive Officer since November 2016 and was elected a director of the Company in January 2017. From May 2016 through January 2017, Ms. Apsey served as the Company’s Executive Vice President and Chief Business Unit Officer, where she was responsible for leading all aspects of the financial and operational performance of our Regulated Operating Subsidiaries and the Company’s development. She had previously served as the Company’s Executive Vice President, Chief Business Unit Officer and President, ITC Michigan since February 2015 where she was responsible for leading all aspects of the financial and operational performance of the Company’s Regulated Operating Subsidiaries and acting as the business unit head and president of the ITCTransmission and METC operating companies. Ms. Apsey previously served as a director of the Fortis utility subsidiary, FortisAlberta Inc. from 2017 to 2025. The Board selected Ms. Apsey to serve as a director due to her position as Chief Executive Officer of the Company.

Leanne M. Bell, 65. Ms. Bell became a director of the Company in February 2022. Ms. Bell is a retired financial and power infrastructure expert with a portfolio of board work spanning the infrastructure space in both the United States and Europe. She has overseen the investment of more than $6 billion in global power infrastructure projects and companies. Before committing full time to non-executive board roles in 2014, Ms. Bell was Chief Financial Officer of Synergy Renewables LLC, Managing Director of Tiger Infrastructure Partners (formerly Lehman Brothers Global Infrastructure Partners) and Managing Director of GE Energy Financial Services. She currently sits on the boards of Sonnedix and Third Coast Midstream, LLC. She previously served on the boards of Nadara Energy Services Limited from May 2017 to December 2025, Nassau Financial Group from July 2016 to July 2024, Onward Energy Services from August 2018 to December 2021, and John Laing Group from December 2020 to October 2021. The Board selected Ms. Bell to serve as a director due to her expansive career in the financial and energy industries. Ms. Bell serves on the Audit and Risk Committee and the Board has determined that Ms. Bell is an “audit committee financial expert,” as that term is defined under applicable SEC rules.

Diane C. Bridgewater, 63. Ms. Bridgewater became a director of the Company in January 2026. Ms. Bridgewater retired from Life Care Services LLC, an owner and provider of senior lifestyle communities and services, in January 2026, where she most recently served as a Strategic Advisor. While at Life Care Services LLC she served as EVP & Chief Administrative & Strategic Officer in 2024 and as EVP, Chief Financial & Administrative Officer from 2011 to 2023. She currently serves on the boards of Guide One Insurance, Des Moines University, The Community Foundation of Greater Des Moines, and previously served on the board of Casey’s from 2007 to 2023. The Board selected Ms. Bridgewater to serve as a director due to her financial and leadership experience as well as her familiarity with the geographic region in which the Company operates and conducts business. Ms. Bridgewater serves on the Audit and Risk Committee and the Board has determined that Ms. Bridgewater is an “audit committee financial expert,” as that term is defined under applicable SEC rules.

Geoffrey S. Chatas 63. Mr. Chatas became a director of the Company in November 2024. Mr. Chatas is the Senior Vice President for Operations at Yale University. Prior to this position he was the Executive Vice President and Chief Financial Officer at the University of Michigan where he has served as the President’s Chief Advisor on financial matters from October 2021 to November 2025. He was the Senior Vice President and Chief Operating Officer for Georgetown University from February 2018 to September 2021, and prior to that, he was the Vice President for Business and Finance and Chief Financial Officer at The Ohio State University. In 2015,

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Gov. John Kasich appointed Mr. Chatas to run Ohio’s Task Force on Affordability and Efficiency in Higher Education. Before Mr. Chatas’ career in higher education, he served as managing director for the Infrastructure Investment Fund at JP Morgan Asset Management and served in various finance roles at Progress Energy, Inc., American Electric Power, Banc One Capital Corporation and Citibank. The board selected Mr. Chatas to serve as a director due to his experience within the energy and financial industries as well as his leadership capabilities. Mr. Chatas serves on the Audit and Risk Committee and the Board has determined that Mr. Chatas is an “audit committee financial expert,” as that term is defined under applicable SEC rules.

Rowena G. Crosbie, 62. Ms. Crosbie became a director of the Company in January 2026. She is the President of Tero International, a corporate training firm, which she founded in 1993. She currently serves on the boards of the Delta Dental of Iowa Foundation, MAKO Enterprises, LLC, and Grand View University. The board selected Ms. Crosbie to serve as a director due to her leadership experience and familiarity within the geographic region in which the Company operates and conducts its business. Ms. Crosbie serves on the Governance and Human Resources Committee.

Robert A. Elliott, 70. Mr. Elliott became a director of the Company in January 2017. Mr. Elliott has served as President and Owner of Elliott Accounting, an accounting, income tax and management advisory services organization in Tucson, Arizona, since 1983. From 2001 to 2025, he also served as an Investment Advisor Representative for Greenberg Financial Group, a brokerage firm. Mr. Elliott currently serves on the board of directors of AAA Mountain West Group and has served since 2016. He previously served as a board member of UNS Energy Corporation, a subsidiary of Fortis, from 2014 through 2022, serving as the Chair of the Board until 2021. He previously served on the board of directors of AAA Auto Club Partners from 2017 to 2022 and AAA Arizona Inc. from 2007 to 2016. The Board selected Mr. Elliott to serve as a director because of his accounting experience, his familiarity with Fortis subsidiary operations and his experience serving as a leader on other boards of directors. Mr. Elliott serves as Chairperson of the Audit and Risk Committee, and the Board has determined that Mr. Elliott is an “audit committee financial expert,” as that term is defined under applicable SEC rules.

Debora M. Frodl, 60. Ms. Frodl became a director of the Company in August 2020. Ms. Frodl is the founder of DF Strategies, a strategic consultancy firm in Minneapolis, MN, since 2018. She previously enjoyed a 28-year career at General Electric, where she most recently was Global Executive Director, Ecomagination from December 2012 to December 2017. Ms. Frodl gained over twenty years of senior executive experience at GE Capital, serving in roles including Senior Vice President and CEO and President. Ms. Frodl formerly served on the board of Renewable Energy Group from March 2018 to June 2022, Spruce Power Holdings (formerly XL Fleet Corporation) from May 2018 to December 2022 and Spring Valley Acquisition Corporation from November 2020 to May 2022. Since 2014, Ms. Frodl has served as an ambassador for the US Department of Energy’s Clean Energy, Education & Empowerment for Women Initiative. She also serves on the board of directors of Spring Valley Acquisition Corp., the Advisory Board for the National Renewable Energy Lab, Joint Institute of Strategic Energy Analysis, the University of Minnesota, Institute on the Environment and Greenbelt Capital Partners. The Board selected Ms. Frodl to serve as a director due to her career in the energy industry, and her leadership experience and familiarity within the geographic region in which the Company operates and conducts its business. Ms. Frodl serves as the Chair of the Governance and Human Resources Committee.

Lt. Gen. Ronnie Hawkins, Jr., USAF, Retired, 70. Lt. Gen. Hawkins, Jr. became a director of the Company in June 2020. Lt. Gen. Hawkins, Jr. was appointed as President of Angelo State University, which is part of the Texas Tech University System, in 2020. Lt. Gen. Hawkins, Jr. is also the President and CEO of the Hawkins Group, a consultancy focusing on digital, information technology and cybersecurity challenges for Fortune 500 clients and the U.S. Government. He founded the Hawkins Group in 2015 after serving more than a 37-year decorated career in the United States Air Force, which included leadership roles in critical infrastructure and key information systems used by the Department of Defense and its coalition partners. Lt. Gen. Hawkins, Jr. currently serves on the board of directors of Tyler Technologies. The Board selected Lt. Gen. Hawkins, Jr. due to his vast knowledge of cybersecurity and information systems as well as his leadership experience. Lt. Gen. Hawkins, Jr. serves on the Governance and Human Resources Committee.

David G. Hutchens, 59. Mr. Hutchens became a director of the Company in January 2021. Mr. Hutchens is the President and Chief Executive Officer of Fortis and has served as such since January 2021. Prior to his current position, Mr. Hutchens was appointed to Chief Operating Officer of Fortis in January 2020 while concurrently serving as the Chief Executive Officer of UNS Energy Corporation, a position in which he held

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since May 2014. Mr. Hutchens also served as Executive Vice President, Western Utility Operations with Fortis from 2018 to 2020. His career in the energy sector spans more than 30 years, having held a variety of positions at electric and gas utilities in Arizona. He currently serves as a director of Fortis Inc. and the Fortis utility subsidiary Central Hudson and previously served on the UNS Energy Corporation board from 2013 to 2020, the FortisBC board from 2015 to 2025, and the Fortis Alberta board from 2016 to 2022. The Board selected Mr. Hutchens to serve based on his relevant business and leadership experience and because he is a director representative of Fortis. Mr. Hutchens serves on the Governance and Human Resources Committee.

James P. Laurito, 69. Mr. Laurito became a director of the Company in October 2016. Mr. Laurito retired from Fortis in December 2021. He previously served as Fortis’ Executive Vice President, Business Development since April 2016 and as Chief Technology Officer from 2018 until his retirement. Previously, Mr. Laurito served as the President and Chief Executive Officer of Fortis’ Central Hudson Gas & Electric Corporation subsidiary from January 2010 to November 2014. Prior to joining Central Hudson, Mr. Laurito served as the President and Chief Executive Officer of both New York State Electric and Gas Corporation and Rochester Gas and Electric Corporation, subsidiaries of Avangrid, Inc. Mr. Laurito formerly served as a director of the Fortis Inc. subsidiaries Central Hudson Gas & Electric Corporation, Newfoundland Power, UNS Energy, and Belize Electricity Ltd. from 2016 to 2023. He currently serves on the boards of Bowman Consulting Group, where he serves as Chair, CTC Global Corp., and Stone Mountain Technologies, Inc. He is also an Operating Partner with Energy Impact Partners, LP, Greenbelt Capital Partners, and an Industry Advisor to EQT Partners, Inc. The Board selected Mr. Laurito to serve due to his expansive background in the utility industry and his regulatory knowledge. Mr. Laurito serves on the Governance and Human Resources Committee.

Jocelyn H. Perry, 55. Ms. Perry became a director of the Company in January 2022. Ms. Perry has served as Fortis’ Executive Vice President and Chief Financial Officer since 2018. Previously, Ms. Perry was the President and Chief Executive Officer of Fortis’ Newfoundland Power subsidiary from 2017 to 2018 and as its Chief Operating Officer from 2016 to 2017. Ms. Perry currently serves on the board of Fortis’ subsidiary UNS Energy Corporation and previously served on the board of FortisBC from 2019 to 2022. The Board selected Ms. Perry to serve based on her relevant business and leadership experience and because she is a director representative of Fortis. Ms. Perry serves on the Audit and Risk Committee.

Sandra E. Pierce, 67. Ms. Pierce was appointed as Chair of the Board of Directors of the Company in May 2020 and has served as a director of the Company since January 2017. Ms. Pierce retired from Huntington National Bank in December 2023 where she served as Senior Executive Vice President, Private Client Group & Regional Banking Director and Chair of Michigan for Huntington National Bank since 2016. Ms. Pierce joined Huntington in 2016 after its merger with FirstMerit Corporation in 2016. While at FirstMerit, Ms. Pierce served as Vice Chairman of FirstMerit Corporation and Chairman and CEO of FirstMerit Michigan, from 2013 to 2016. Ms. Pierce currently serves as a board member of Penske Automotive Group, American Axle & Manufacturing, Inc. and Barton Malow Enterprises. She also serves as the chair of the Detroit Economic Club, the chair of Henry Ford Health Foundation, as a board member of Renaissance MAC, and as Chair-Elect & Vice Chair of the Detroit Riverfront Conservancy. Previously, Ms. Pierce served as the vice chair of Business Leaders of Michigan, chair of Henry Ford Health System and chair of the Detroit Financial Advisory Board. Ms. Pierce was appointed by Governor Whitmer to Michigan State University’s Board of Trustees in December 2022. The Board selected Ms. Pierce to serve as a director due to her leadership experience and familiarity with the geographic region in which the Company operates and conducts business.

Kevin L. Prust, 70. Mr. Prust became a director of the Company in January 2017. Mr. Prust retired in 2014 as Executive Vice President and Chief Financial Officer of The Weitz Company, LLC, a large national and international construction firm, a position he held since joining the company in 2009. Prior to that, Mr. Prust was with McGladrey & Pullen LLP, a national CPA firm, from 1978 through 2008 serving in various positions and becoming partner in 1985. Mr. Prust previously served on the board of Mercy Medical Center, in Des Moines, Iowa from 2009 to 2018. In 2015 Mr. Prust served on the board of Stock Building Supply Holdings, Inc. until the company was acquired. The Board selected Mr. Prust to serve as a director because of the expansive financial and accounting experience he obtained as a chief financial officer as well as his familiarity with the geographic region in which the Company operates and conducts business. Mr. Prust serves on the Audit and Risk Committee and the Board has determined that Mr. Prust is an “audit committee financial expert,” as that term is defined under applicable SEC rules.

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A. Douglas Rothwell, 69. Mr. Rothwell became a director of the Company in October 2017. Mr. Rothwell served as President and CEO of Business Leaders for Michigan - a business roundtable of the state’s top 100 CEOs from 2005 through 2020. Mr. Rothwell currently serves as an Executive in Residence for Economic Development at the University of North Carolina at Chapel Hill. He previously chaired the Michigan Economic Development Corporation, the American Center for Mobility and the UNC Board of Visitors. The Board selected Mr. Rothwell to serve as a director because of his vast experience working with business leaders in various industries to foster business development and growth and his familiarity and business contacts within the geographic region in which the Company operates and conducts business. Mr. Rothwell serves on the Governance and Human Resources Committee.

Brian C. Walker, 64. Mr. Walker became a director of the Company in November 2024. Mr. Walker served as Operating Partner of the private equity firm Huron Capital from February 2019 until December 2023. Mr. Walker retired from Herman Miller Inc. in 2018 after a 29-year career where he most recently served as its President and CEO since July 2004. Mr. Walker currently serves on the Audit and Compensation Committee of the Board of Directors of Gentex Corporation, is the Audit Committee Chair of Universal Forest Products, Inc., and is on the Board of Directors of Horizon Bank. The Board selected Mr. Walker to serve as a director due to his extensive leadership experience and background as well as his familiarity with the geographic region in which the Company operates and conducts business. Mr. Walker serves on the Audit and Risk Committee and the Board has determined that Mr. Walker is an “audit committee financial expert,” as that term is defined under applicable SEC rules.

EXECUTIVE OFFICERS

Set forth below are the names, ages and titles of our current executive officers and a description of their business experience. Our executive officers serve as executive officers at the pleasure of the Board of Directors.

Linda H. Apsey, 56. Ms. Apsey’s background is described above under “Directors.”

Gretchen L. Holloway, 51. Ms. Holloway was named Senior Vice President and Chief Financial Officer in July 2017. Prior to this role, Ms. Holloway served as Vice President, Interim Chief Financial Officer and Treasurer, a position in which she served since October 2016. In her role, Ms. Holloway is responsible for the Company’s accounting, internal audit, treasury, financial planning and analysis, management reporting, risk management and tax functions. From May 2016 to October 2016, Ms. Holloway was Vice President and Treasurer and from November 2015 until May 2016, Ms. Holloway served as Vice President, Finance and Treasurer of the Company. In this role and her immediate past role, she was responsible for all treasury and corporate planning activities including cash management and as the Company’s liaison with the investment banking community and rating agencies. Ms. Holloway served from February 2015 to November 2015 as Vice President, Finance of the Company, where she was responsible for corporate finance activities including oversight of the budget and forecast processes and other financial analysis. Ms. Holloway currently serves on the Board of Directors and is the Chair of the Audit & Risk Committee for Kodiak Gas Services. She previously served on the board of the Fortis subsidiary, Caribbean Utilities Company, and as a member of their Audit Committee from May 2021 to May 2023. Ms. Holloway also serves on the Board of Trustees for the Children’s Foundation, and is the Chair of the Finance & Audit Committee for the Children’s Foundation.

Brian Slocum, 49. Mr. Slocum was named Senior Vice President and Chief Operating Officer in February 2022. In his role, Mr. Slocum is responsible for the Company’s system operations, planning, engineering, supply chain, field construction and maintenance, and information technology. Mr. Slocum joined the Company in 2003 and held various engineer positions before being promoted to Director of Engineering in 2008. He was named Vice President of Engineering in 2011 and was appointed to Vice President of Operations in February 2015. Mr. Slocum serves on the board for Henry Ford Providence Foundation and the advisory board for North American Transmission Forum and the Michigan Intelligence Operations Center for Homeland Security. He is a current member of the Reliability Issues Steering Committee of NERC, and previously served as Chair.

Christine Mason Soneral, 53. Ms. Mason Soneral has served as Senior Vice President, General Counsel, Secretary and Chief Compliance Officer since October 2020. She was named Senior Vice President and General Counsel in April 2015 and served as Vice President and General Counsel from February 2015 through this appointment. She is responsible for all corporate legal affairs and the leadership of our legal department, which includes the legal, real estate, contract administration and corporate compliance functions. Prior to this

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role, Ms. Mason Soneral was Vice President and General Counsel-Utility Operations since 2007 and was responsible for legal matters connected with the operations, capital projects, contract, regulatory, property and litigation of the Company’s Regulated Operating Subsidiaries. Ms. Mason Soneral currently serves as a member of the Michigan State University College of Social Science's External Advisory Board and is a Co-Founder and Director of Michigan State University’s Women’s Leadership Institute. She also serves on the Board of Directors at Inforum.

Krista Tanner, 51. Ms. Tanner was named President in July 2024 where she oversees the business and operations of the Company. Ms. Tanner served as our Senior Vice President and Chief Business Officer since February 2019 where she was responsible for strategic direction, customer service, local government and community affairs, federal regulatory and legislative affairs, marketing and communications, and financial performance for our Regulated Operating Subsidiaries. Ms. Tanner joined the Company in November 2014 where she served as Vice President, ITC Holdings and President, ITC Midwest. In this role she served as the business unit head, providing leadership and strategic direction for ITC Midwest. Ms. Tanner joined the Company from Alliant Energy, where she served as director of regulatory policy from 2011 to 2014. While at Alliant Energy she directed Alliant Energy’s regional and federal regulatory policy group and led Alliant Energy’s legal strategy across regulatory jurisdictions. Prior to working at Alliant Energy, Ms. Tanner was a state regulatory commissioner on the Iowa Utilities Board from 2007 to 2011. Ms. Tanner previously served as a member of the board of directors of the Midwest Reliability Organization from 2017 to 2019 and as a member of the board of directors of Delta Dental of Iowa from 2015 to 2023. Ms. Tanner currently serves as a member of the board of directors of the Fortis subsidiary, Central Hudson, and is on the board of directors of the American Clean Power Association.

Simon Whitelocke, 53. Mr. Whitelocke was named Senior Vice President and Chief Business Officer in July 2024. Mr. Whitelocke is responsible for the Company’s federal regulatory and government affairs, communications and corporate giving activities, as well as overseeing the strategic direction, government relations and financial performance for the Company’s Regulated Operating Subsidiaries. Prior to this role, Mr. Whitelocke served as Vice President, ITC Holdings and President, ITC Michigan, a position in which he served since July 2016. In this role he served as the business unit head, providing leadership and strategic direction for ITC Michigan. Mr. Whitelocke joined the Company in 2003 and held various positions in accounting and internal audit functions before being appointed to Vice President of Regulatory and External Affairs in January 2011. He was named Vice President and Chief Compliance Officer in February 2015. Mr. Whitelocke is currently a member of the Board of Directors of Food Gatherers, the Michigan Chamber of Commerce, and is vice chair of the boards of Ann Arbor SPARK and Detroit PBS.

Code of Conduct and Ethics

We have adopted a Code of Conduct and Ethics that applies to all of our directors, employees and executive officers, including our chief executive officer, chief financial officer and principal accounting officer. The Code of Conduct and Ethics, as currently in effect (together with any amendments that may be adopted from time to time), is available on our website at www.itc-holdings.com. To the extent required by the Code of Conduct and Ethics or by applicable law, we will post any amendments to the Code of Conduct and Ethics and any waivers that are required to be disclosed by the rules of the SEC on our website, within the required periods.

Insider Trading Policy

All shares of outstanding stock of ITC Holdings are held by its parent company and are not publicly traded. We are not subject to any listing standards. However, we have adopted insider trading policies and procedures applicable to our directors, officers, and employees that we believe are reasonably designed to promote compliance with insider trading laws, rules, and regulations. These policies and procedures are included in our Code of Conduct and Ethics, an excerpt of which is filed as Exhibit 19 to this Form 10-K.

ITEM 11. EXECUTIVE COMPENSATION.

COMPENSATION OF EXECUTIVE OFFICERS AND DIRECTORS

Compensation Discussion and Analysis

The following Compensation Discussion and Analysis describes the elements of compensation for our Chief Executive Officer (or “CEO”), our Chief Financial Officer and the three other most highly compensated executive

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officers who were serving as such at December 31, 2025. We refer to these individuals collectively as the “named executive officers” (or “NEOs”).

The Company’s named executive officers for 2025 were:


Name						Position
Linda H. Apsey						Chief Executive Officer
Gretchen L. Holloway						Senior Vice President and Chief Financial Officer
Brian Slocum						Senior Vice President and Chief Operating Officer
Christine Mason Soneral						Senior Vice President, General Counsel, Corporate Secretary and Chief Compliance Officer
Krista Tanner						President

In November 2025, Ms. Apsey announced her retirement effective March 22, 2026. Ms. Tanner will assume the role of President and Chief Executive Officer on March 23, 2026.

Executive Summary

The Governance and Human Resources Committee (the “Committee”) is responsible for determining the compensation of our NEOs and administering the plans in which the NEOs participate. The goals of our compensation system are to attract first-class executive talent in a competitive environment and to motivate and retain key employees who are crucial to our success by rewarding Company and individual performance that promotes long-term sustainable growth and increases Fortis shareholder value. The key components of our NEOs' compensation package include base salary, annual cash incentive bonuses, long-term equity incentives, as well as certain perquisites and other benefits. In determining the amount of NEO compensation, we consider competitive compensation practices of other utilities and similarly sized organizations, the executive's individual performance against objectives, the executive's responsibilities and expertise, and our performance in relation to annual goals that are designed to strengthen and enhance our value.

The Committee made the following decisions with regard to executive compensation in 2025:

•Base salary increases. Base salary increases were provided to each of our NEOs in 2025 to reward individual performance and to remain competitive and aligned with market.

•Annual cash incentive bonuses. The NEOs earned cash incentive bonuses for 2025 performance of approximately 147% of target. This was based on achieving 95% of the performance targets established under the ACPB in early 2025 and achievement of certain performance factors which resulted in a bonus multiplier of 1.55x. See “Compensation Discussion and Analysis - Key Components of Our NEO Compensation Program - Annual Corporate Performance Bonus.”

•Long-term equity incentives. We granted long-term equity incentive awards to our NEOs effective January 2025. Total award opportunities were set as a percentage of base salary and delivered one-third in the form of SBUs and two-thirds in the form of PBUs.

Overview and Philosophy

The objectives of our compensation program are to attract first-class executive talent in a competitive environment and to motivate and retain key employees who are crucial to our success by rewarding Company and individual performance that promotes long-term sustainable growth and increases in Fortis shareholder value by:

•Performing best-in-class utility operations;

•Improving reliability, reducing congestion, and facilitating access to generation resources; and

•Utilizing our experience and skills to seek and identify opportunities to invest in needed transmission and to optimize the value of those investments.

Our compensation program is designed to motivate and reward individual and corporate performance. Our compensation philosophy is to:

•Provide for flexibility in pay practices to recognize our unique position and growth proposition;

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•Use a market-based pay program aligned with pay-for-performance objectives;

•Leverage incentives, where possible, and align long-term equity incentive awards with improvements in our financial performance and Fortis shareholder value;

•Provide benefits through flexible, cost-effective plans while taking into account business needs and affordability; and

•Provide other non-monetary awards to recognize and incentivize performance.

Risk and Reward Balance

When reviewing the compensation program, the Committee considers its impact on the Company’s risk profile. The Committee believes that the compensation program has been structured with the appropriate mix and design of elements to provide strong incentives for executives to balance risk and reward, without excessive risk taking.

The Committee engaged FW Cook, its independent compensation consultant, to conduct an annual comprehensive compensation program risk assessment. In July 2025, FW Cook reviewed the attributes and structure of our executive compensation programs to identify potential sources of risk in the program design. The review covered compensation plan design and administration/governance risk.

Based on its own analysis and a report from FW Cook concluding that the Company’s compensation programs do not create risks that are reasonably likely to have a material adverse impact on the Company, the Committee concluded that none of our compensation programs and features contain elements that create material risk to the Company. Risk mitigating factors with respect to the Company’s compensation programs included a market competitive pay mix, the linking of pay to performance through annual cash bonus and long-term equity incentive plans, caps on annual cash bonus and long-term equity incentive plan payouts, various performance measures that are both financially and operationally focused, stock ownership guidelines, clawback policy, prohibition on hedging and pledging, oversight by an independent committee of directors, regular review of NEO tally sheets and engagement of an independent compensation consultant.

Benchmarking and Relationship of Compensation Elements

Benchmarking. We reviewed market competitive target pay levels from two distinct market samples, utility and general industry data, as reflected in published surveys. FW Cook compiled data for the following components of compensation — base salary, target annual cash bonus incentive and target long-term incentive, as well as target total cash compensation and target total direct compensation. Position-specific market target pay levels are reviewed for utility-specific data from the Willis Towers Watson Energy Services Executive Compensation Survey and general industry data from the Willis Towers Watson General Industry Executive Compensation Survey. The energy services data is used as our primary source, with the general industry data provided as an additional reference point for positions other than those specific to the utility industry. The market data were aged and size-adjusted to correspond to our adjusted revenue scope. The adjusted revenue scope accounts for our unique business model and reflects the competitive incremental revenue that would normally be embedded in rates to reflect a typical cost of goods sold factor.

Our compensation strategy is to target compensation at the median (50th percentile) of the energy services benchmark data, plus or minus 20%, based on consideration of individual characteristics (performance, experience, etc.), internal equity and other factors. In November 2024, the Committee reviewed the benchmarking study conducted by its independent consultant comparing NEO target total direct compensation, which is the sum of base salary, target annual incentives and target long-term incentives, to the 25th, 50th and 75th percentile survey data to assess the market competitiveness of our compensation opportunities. Overall, the study found target total direct compensation provided to our NEOs varied with certain executives positioned within the targeted competitive range, and in some cases, exceeded the targeted competitive position. Competitive positioning reflects a combination of median base salaries, above median target bonus as a percent of base salary and median long-term equity incentive opportunities. The Committee continues to monitor and balance competitive practices, talent needs and cost considerations when setting compensation.

Use of Tally Sheets. The Committee reviews tally sheets, every other year, as prepared by management to facilitate its assessment of the total annual compensation of our NEOs. The tally sheets contain annual cash compensation (salary and bonuses), long-term equity incentives, benefit contributions and perquisites. In

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addition, the tally sheets include retirement program balances, outstanding vested and unvested equity values and potential severance and termination scenario values.

Pay Review Process. In addition to the Committee’s benchmarking analysis, our CEO reviewed and examined market survey compensation levels and practices, as well as individual responsibilities and performance, our compensation philosophy and other related information to develop proposed compensation for each of our NEOs, other than herself. Ms. Apsey evaluated the performance of the NEOs, other than herself, and made recommendations on their salaries, target cash bonus incentive levels and long-term equity incentive awards. The Committee considered these recommendations in its decision making and conferred with FW Cook to understand the impact and result of any such recommendations. The Committee uses market data from FW Cook and makes recommendations on Ms. Apsey’s salary, cash bonus incentive targets and long-term equity incentive awards to the Board of Directors. The Board of Directors (other than Ms. Apsey) evaluates Ms. Apsey’s performance and considers the Committee’s recommendations in its decision making.

The Committee reviewed and considered each element of compensation and the resulting target total direct compensation, along with the objectives of our compensation program, the input of the CEO and the market data to set the 2025 target pay levels. The Committee did not determine the mix of compensation elements using a pre-set formula. In addition to the market data, the Committee also considered individual and Company performance, retention concerns, the importance of the position, internal equity and other factors in setting individual executive compensation levels.

Key Components of Our NEO Compensation Program

The key components of our executive compensation program are discussed below.

•Base Salary — provides sufficient competitive pay to attract and retain experienced and successful executives.

•Cash Bonus Incentive — encourages and rewards contributions to our annual corporate performance goals.

•Long Term Equity Incentives — encourages a multi-year focus on performance, rewards building long-term Fortis shareholder value and helps retain NEOs.

The other elements of our executive compensation program are discussed below under the heading “Other Components of Our Executive Compensation Program”, which summarizes the benefit programs that are available to our NEOs.

Base Salary

The Committee annually reviews and approves the base salaries, and any adjustments thereto, of the NEOs. In making these determinations, the Committee considers the executive’s job responsibilities, individual performance, leadership and years of experience, the performance of the Company, the recommendation of the CEO (except for the base salary of the CEO) and the target total direct compensation package as well as the benchmarking analysis conducted by its advisor.

The 2025 annualized base salaries for the NEOs, including any year-over-year change, were:


NEO	2024 Base Salary		2025 Base Salary		Percent Increase
Linda H. Apsey	$	936,000	$	973,400	4.0	%
Gretchen L. Holloway	447,700		461,100		3.0	%
Brian Slocum	468,600		538,900		15.0	%
Christine Mason Soneral	430,500		452,000		5.0	%
Krista Tanner	535,000		556,400		4.0	%

The increase for Mr. Slocum considered the market median data and his sustained performance.

Annual Corporate Performance Bonus

Early each year, the Committee approves our ACPB goals and targets, which are based on key Company objectives relating to operational excellence and superior financial performance. The corporate performance goals and targets were designed to align the interests of customers, the shareholder and management, and

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encourage teamwork and coordination among all of our executives and employees with a common focus on the growth and success of the Company.

The ACPB goals were individually weighted. Weights were assigned to each goal based on areas of focus during the year and difficulty in achieving target performance. Weights were also assigned so that there was a balance between operational and financial goals. Each goal operated independently, and, for most goals, there was not a range of acceptable performance; if a goal was not achieved, there was no payout for that goal. Where performance goals were stated in a range, the threshold goals were generally expected to be achieved while the target goals were considered “stretch” goals with lower expectation of achievement. The bonus goals were designed to be challenging to meet, while remaining achievable.

For 2025, the ACPB consisted of three primary measurement categories: Financial, Safety & Compliance, and System Performance. System Performance represented 60% of the target bonus opportunity, reflecting the inherent importance of driving operational performance, reliability and needed investment in our transmission system for the benefit of our customers.

Target levels for the corporate performance goals were determined based on our annual and long-term strategic plans, historical performance, expectations for future growth and desired improvement over time. Our safety, operations and security goals were established to deliver high performance in core Company operations. Benchmarks and metrics were used in connection with these goals to establish a level of performance in the top decile or quartile within our industry. Likewise, our security goals led to the deployment of industry leading practices resulting in a generally enhanced security posture.

Corporate performance goal criteria approved by the Committee for 2025, the rationale for the target goal (in some cases in relation to the prior year target) and actual bonus results, were as set forth below.

Financial goals represented 20% of the total maximum annual bonus target and included specific measures for Non-Field Operation and Maintenance Expense and Net Income.


Category	Goal	Rationale for Goal	Rationale for Target Goal	Potential Payout		2025 Results		Actual Payout
Financial 20% Maximum Potential Payout	Non-field Operation and Maintenance Expense and General and Administrative Expenses	Controlling general and administrative expenses is an important part of controlling rates charged to transmission customers.	Target is based on the 2025 Board-approved budget. Non-Field O&M and G&A expense at or under budget of $182M.	10	%	$172M		10	%
	Adjusted Net Income (1)	Represents the Company’s financial performance as it reflects a true measure of earnings contributions from our Regulated Operating Subsidiaries.	Target is based on the 2025 Board-approved budget. Adjusted Net Income at or above $660M to achieve 10%; Adjusted Net Income at or above $627M to achieve 5%.	5 - 10%		$679	M	10	%
Total				20	%			20	%

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Safety & Compliance goals represented 20% of the total maximum annual bonus target and included specific measures for Lost Time, Recordable Incidents and Security.


Category	Goal	Rationale for Goal	Rationale for Target	Potential Payout		2025 Results	Actual Payout
Safety & Compliance 20% Maximum Potential Payout	Safety as measured by leading indicators	Evolving our safety programs to include leading indicators.	Reflects company and industry movement in safety culture focus to create capacity to avoid serious injury. Implement 9 of the highest priority recommendations from the High-Energy Control Assessment (HECA).	5	%	Completed	5	%
	Safety as measured by recordable incidents and lost time	Maintaining the safety of our employees and contractors is a core value and is at the foundation of our success.	Target number of incidents was based on industry top decile performance, which reflects an aggressive view and philosophy on the importance of safety. 6 or fewer recordable incidents for injuries to Company employees and specified contract employees with no more than 2 being Lost Work Day cases and zero fatalities.	5	%	4 / 0	5	%
	Security	Maintaining cybersecurity is critical to ensuring system reliability and ongoing operations.	Goal focused on implementing updated security objectives. Emphasized securing our information systems and helping protect our most important assets. Implementation of the 2025 Cyber Security Plan, as presented to and approved by the Board of Directors.	5	%	Completed	5	%
	Wildfire Plan	Evolve wildfire mitigation and response plan	Goal focused on (1) adopting applicable ICF wildfire mitigation recommendations; (2) developing enhanced wildfire response implementation plan; and (3) conducting a wildfire response tabletop exercise.	5	%	Completed	5	%
Total				20	%		20	%

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System Performance goals represented 60% of the total maximum annual bonus target and included specific measures for System Outages, Maintenance Plans and Capital Project Plan.


Category	Goal	Rationale for Goal	Rationale for Target	Potential Payout		2025 Results	Actual Payout
System Performance 60% Maximum Potential Payout	Outage frequency	Reducing and limiting system outages are critical to ensuring system reliability.	Target design unchanged from prior year; all targets aligned with industry benchmark data. Number of Forced, Sustained Line Outages, excluding the "External" cause classification, for: ITCTransmission (12 or fewer, representing top decile performance); METC (25 or fewer, representing top decile performance); ITC Midwest (59 or fewer, representing top decile performance, no more than 48 at the 69kV level representing top quartile performance.); Each target is worth 5%.	15	%	ITCTransmission - 11 METC - 13 ITC Midwest - 63 / 43	10	%
	Field Operation and Maintenance Plan	Performing necessary preventive maintenance is critical to ensuring system reliability.	Target is reflective of goal to complete the normal maintenance schedule of high priority maintenance activities. Complete high priority 2025 Field O&M Initiatives for: ITCTransmission (15) METC (13) ITC Midwest (11) Each target worth 5%. Payout reduced by 5% if not at or under Field O&M overall maintenance budget of $100.9M.	15	%	All high priority Field O&M initiatives completed under budget at $96M	15	%
	Capital Project Plan	Performing necessary system upgrades is critical to ensuring system reliability, providing a robust transmission grid and delivering financial performance.	Target is based on accrued capital investment. The maximum payout represents the risk-adjusted capital investment plan for 2025, with a threshold level also established. Complete $1,064M of the 2025 Capital Project Plan to achieve 30%; Complete $1,008M to achieve 15%.	15 - 30%		$1,338M	30	%
Total				60	%		55	%

Total Bonus (as a percent of target bonus level)				100	%		95	%

____________________________

(1)We utilize adjusted net income as a criterion in measuring achievement of financial goals for our ACPB. This non-GAAP financial measure reconciles to net income of our Regulated Operating Subsidiaries with adjustments under $1 million.

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Additionally, our executives, including the NEOs, are eligible for an executive bonus multiplier. To further motivate management to provide value to the shareholder, in 2025, we included a performance factor under which their ACPB payouts could be increased for outperformance by as much as 100% based on multiple measures, as follows:

Measure

Threshold

Maximum

Achievement

Multiplier

Weight

Result

Capital Investment Plan

$1,064M

$1,232M

$1,338M

2.00x

50%

1.00x

Adjusted Consolidated Net Income (1)

$525M

$540M

$525M

1.00x

20%

0.20x

Strategic Plan Objective

Objective Not Achieved

Objective Achieved

Objective Not Achieved

1.00x

25%

0.25x

Engagement Index

4.16

4.29

4.33

2.00x

0.10x

Bonus Multiplier

1.55x

____________________________

(1)We utilize adjusted consolidated net income as a criterion in measuring achievement of financial goals for the executive bonus multiplier. This non-GAAP financial measure reconciles to consolidated net income of ITC Holdings as follows:


(In millions of USD)	2025
Net income	$	519
Adjustments related to additional Board-approved development costs	4
Adjustment related to income taxes	3
Adjustment related to changes in Investment Holdings dividend policy/levels	(1)


Adjusted consolidated net income	$	525

Each measure has an established scale, which includes a threshold level equating to a 1.00x multiplier, to a maximum of 2.00x, which would increase the bonus by 100% to a maximum of 200% of target. Performance below the threshold level has no impact on the bonus payment. Achievement against performance scales related to each of the above metrics produced an executive bonus multiplier of 1.55x. This performance factor was applied to the ACPB factor of 95% to produce a final payment of approximately 147% of target.

Bonuses are based on a target bonus, which for each executive is a percentage of his or her base salary. The Committee considers each individual’s job responsibilities and the results of its benchmarking analysis when determining the base bonus percentage for the executive officers, including the NEOs, which we refer to as the “target bonus levels.” Target bonus levels for 2025 were 100% of base salary for Mses. Apsey, Holloway, Mason Soneral and Tanner and 75% of base salary for Mr. Slocum.

Long-Term Equity Incentive

The Committee has established long-term incentive targets as a percentage of the base salary for each NEO in consideration of benchmarking data on total direct compensation, the importance of the NEO’s position to the success of the Company, our need to create meaningful incentives to enhance performance and the culture of teamwork that makes our Company successful. The Committee does not have a pre-established targeted allocation of total direct compensation.

The Committee has the power to recommend awards of SBUs or PBUs to Fortis under the Fortis Inc. Omnibus Equity Plan with the terms of each award set forth in a written agreement with the recipient. Grants made in 2025 to the NEOs were made pursuant to terms stated in the SBU and PBU award agreements.

Fortis maintains, and has the sole authority to issue awards under the Fortis Inc. Omnibus Equity Plan. Prior to the effectiveness of the Fortis Inc. Omnibus Equity Plan, Fortis maintained the Fortis 2020 Restricted Share Unit Plan. Additionally, the Company maintained the Executive Omnibus Plan. Annual awards under the Fortis Inc. Omnibus Equity Plan are made (and historically under the Fortis 2020 Restricted Share Unit Plan and the Executive Omnibus Plan, were made) to our NEOs, based on the Committee’s (for our NEOs other than our CEO) and our Board of Directors’ (for our CEO) recommendations to Fortis’ Board of Directors. In February 2025, the Committee recommended to our Board of Directors, and our Board of Directors recommended that Fortis’ Board of Directors approve grants of SBUs and PBUs to the NEOs, which recommendations (including size of grant and award mix) were based on, for our NEOs other than the CEO, our CEO’s recommendation to the Committee, and for our CEO and other NEOs, the Committee’s assessment of the performance of the

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Company and the executive, market practice, comparisons to benchmarking data, expense to the Company and the practice of other U.S. Fortis subsidiary companies. The Fortis Board of Directors ratified the NEO awards, as recommended, in February 2025. Award opportunities for the NEOs were provided in a mix of PBUs (weighted 67%) and SBUs (weighted 33%). The PBUs have a three-year performance period and can be earned between 0% and 200% for results in three separate measures, TSR (relative to Fortis’ peer group) weighted at 45%, ITC cumulative consolidated net income weighted at 45% and Fortis Climate-Related Goals weighted at 10%. These PBU metrics were selected because TSR aligns with the Fortis shareholder experience, cumulative consolidated net income measures our sustained growth (organic and development), cost management and efficiency and climate-related targets support a corporate-wide goal to advance climate adaptation and mitigation activities and performance. SBUs vest over the same three-year period based on the recipient’s continued service. Each unit is generally equivalent to one common share of Fortis (each, a “Common Share”) (as traded on the NYSE) and earned units are payable in cash or Common Shares. The awards were designed to reward, motivate and encourage long-term performance, act as a retention mechanism and further align the interests of the NEOs with the interests of the Fortis shareholders. Total value for the award for each grantee was determined based on a percentage of salary. For the NEOs, when the 2025 awards were made, the award values were targeted to be:


NEO	Grant Value Percent of Salary
Ms. Apsey	250	%
Ms. Holloway	175	%
Mr. Slocum	150	%
Ms. Mason Soneral	175	%
Ms. Tanner	185	%

The amounts and more detailed terms of the 2025 SBU and PBU grants made under the Fortis Inc. Omnibus Equity Plan are described in the narrative following the Grants of Plan-Based Awards Table.

Other Components of Our Executive Compensation Program

Pension Benefits. As is common in our industry and as established pursuant to our initial formation requirements included in the acquisition agreement with DTE Energy for ITCTransmission, we maintain a tax-qualified defined benefit retirement plan for eligible employees, comprised of a traditional pension component and a cash balance component. All employees, including the NEOs, participate in either the traditional component or the cash balance component. We have also established a supplemental nonqualified, noncontributory retirement benefit plan for selected management employees: the Executive Supplemental Retirement Plan, or ESRP, in which all of the NEOs participate. This plan provides for benefits that supplement those provided by our qualified defined benefit retirement plan. Benefits payable to the NEOs pursuant to the retirement plans are set by the terms of those plans. The Committee exercises no regular discretionary authority in the determination of benefits. The retirement plans may be modified, amended or terminated at any time, although no such action may reduce a NEO’s earned benefits. See “Pension Benefits” for information regarding participation by the NEOs in our retirement plans as well as a description of the terms of the plans.

Benefits and Perquisites. The NEOs participate in a variety of benefit programs, which are designed to enable us to attract and retain our workforce in a competitive marketplace. These programs include our Savings and Investment Plan, which consists of an employee deferral contribution component and an employer safe-harbor matching contribution component.

Our NEOs are provided a limited number of perquisites in addition to benefits provided to our other employees. The purpose of these perquisites is to minimize distractions from the NEOs’ attention to important Company initiatives, to facilitate their access to work functions and personnel, and to encourage interactions among NEOs and others within professional, business and local communities. NEOs are provided perquisites such as auto allowance, financial, estate and legal planning, income tax return preparation, annual physical, club memberships, relocation expenses and personal liability insurance. Additionally, we own aircraft to facilitate the business travel schedules of our executives and other employees, particularly to locations that do not provide efficient commercial flight schedules. Ms. Apsey and guests who travel with her are permitted to travel for personal business on our aircraft, with an annual maximum of 50 flight hours for such personal travel. Ms.

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Apsey incurs imputed income for all guests and herself for personal travel in the amount of the incremental cost to the Company of such travel.

We purchase tickets to various sporting, civic, cultural, charity and entertainment events. We use these tickets for business development, partnership building, charitable donations and community involvement. If not used for business purposes, we may make these tickets available to employees, including the NEOs, as a form of recognition and reward for their efforts.

None of the NEOs are reimbursed for income taxes associated with the value of the perquisites. The Committee continues to monitor and review the Company’s perquisite program. Perquisites are further discussed in footnote 4 to the “Summary Compensation Table.”

Potential Severance Compensation. Pursuant to their employment agreements, each NEO is entitled to certain benefits and payments upon a termination of his or her employment. Benefits and payments to be provided vary based on the circumstances of the termination. We believe it is important to provide these protections in order to ensure our NEOs will remain engaged and committed to us during an acquisition of the Company or other transition in management. See “Employment Agreements and Potential Payments Upon Termination or Change in Control” for further detail on these employment agreements, including a discussion of the compensation to be provided upon termination or a change in control.

Clawback Policy

The Board has approved clawback provisions for certain compensation plans. These provisions allow the Board to require the forfeiture, recoupment or repayment of compensation if there is a restatement of financial results or fraud, gross negligence or intentional misconduct by one or more executives. The Board may also require a return of compensation in the event of a mistake or accounting error in the calculation of such compensation.

Stock Ownership Policy

The Board believes that having a share ownership policy is a key element of strong corporate governance and aligns the interests of management with the interests of Fortis shareholders. Under these guidelines, which became effective January 1, 2020, officers, including NEOs, must achieve and maintain the applicable level of Fortis Common Shares by the fifth anniversary of when the guidelines first became applicable to the individual. The current levels are as follows:


Position						Ownership Level
Chief Executive Officer						2x annual base salary
Executive and Senior Vice Presidents						1.5x annual base salary
Vice Presidents						1x annual base salary

The securities that qualify for the purpose of determining compliance with the policy are Common Shares and the executive’s outstanding SBU awards. Share ownership levels include Fortis securities beneficially owned: (i) in a trust; (ii) by the executive’s spouse; and (iii) by the executive’s minor children. Any executive that fails to maintain minimum stock ownership under these guidelines must receive settlement of vesting equity-based compensation awards as Common Shares and may not dispose of any Common Shares beneficially owned. As of December 31, 2025, each of the NEOs was in compliance with this policy.

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Governance and Human Resources Committee Report

The Governance and Human Resources Committee has reviewed and discussed this Compensation Discussion and Analysis with management and, based on the review and discussions with management, has recommended to the Board of Directors that the Compensation Discussion and Analysis be included in this report.

DEBORA M. FRODL

ROWENA G. CROSBIE

RONNIE D. HAWKINS, JR.

DAVID G. HUTCHENS

JAMES P. LAURITO

A. DOUGLAS ROTHWELL

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Summary Compensation

The following table provides a summary of compensation paid or accrued by the Company and its subsidiaries to or on behalf of the NEOs for services rendered by them during each of the last three calendar years, as required by applicable SEC rules and regulations. The material terms of plans and agreements pursuant to which certain items set forth below were paid are discussed elsewhere in Compensation of Executive Officers and Directors.

Summary Compensation Table


Name	Year	Salary ($)		Stock Awards ($) (1)		Non-Equity Incentive Plan Compensation ($) (2)		Change in Pension Value & Non-qualified Deferred Compensation Earnings ($)(3)		All Other Compensation ($) (4)		Total ($)
(a)	(b)	(c)		(e)		(f)		(g)		(h)		(i)
Linda H. Apsey, CEO	2025	$	977,145	$	2,433,500	$	1,433,332	$	506,039	$	159,563	$	5,509,579
	2024	943,200		2,340,000		1,684,800		295,477		125,049		5,388,526
	2023	900,000		2,249,962		999,000		468,908		139,034		4,756,904

Gretchen L. Holloway, SVP & CFO	2025	462,874		806,925		678,970		248,669		42,599		2,240,037
	2024	451,143		1,383,475		805,860		106,106		42,149		2,788,733
	2023	434,699		760,731		482,517		218,843		41,060		1,937,850

Brian Slocum, SVP & COO	2025	540,972		808,350		595,148		235,580		43,000		2,223,050
	2024	472,205		656,040		632,610		82,490		41,503		1,884,848
	2023	426,000		596,407		283,716		190,421		40,971		1,537,515

Christine Mason Soneral, SVP, General Counsel, Secretary & CCO	2025	453,738		791,000		655,570		268,349		43,000		2,211,657
	2024	433,812		753,375		774,900		121,237		42,489		2,125,813
	2023	417,999		731,500		463,980		246,282		40,300		1,900,061

Krista Tanner, President	2025	558,540		1,029,340		819,299		234,644		47,751		2,689,574
	2024	485,101		763,175		963,000		104,254		74,473		2,390,003
	2023	389,400		681,448		432,234		169,833		61,614		1,734,529

____________________________

(1) The amounts reported in this column represent the grant date fair value of PBU awards and SBU awards granted to the NEOs in 2023 under the Executive Omnibus Plan and the Fortis Inc. 2020 Restricted Share Unit Plan, and in 2024 and 2025 under the Fortis Inc. Omnibus Equity Plan in accordance with FASB Accounting Standards Codification Topic 718, or “ASC 718”.

The grant date fair value of the SBU awards is based on the applicable share price on the grant date. The grant date fair value of the PBU awards is based on the applicable share price on the grant date and the payout of the performance based on probable outcome (which approximates target achievement), and market conditions. The SBU awards and PBU awards are liability awards, subject to remeasurement through the vesting date, and settled in cash or Common Shares, see “Grants of Plan-Based Awards.” The value of the 2025 PBU awards at the grant date assuming that the highest level of performance conditions will be achieved are as follows:


Ms. Apsey	$	3,244,667
Ms. Holloway	1,075,900
Mr. Slocum	1,077,800
Ms. Mason Soneral	1,054,667
Ms. Tanner	1,372,453

(2) The amounts reported in this column include cash awards tied to the achievement of annual Company performance goals under our ACPB in effect for each of 2025, 2024 and 2023. For information regarding the corporate goals for 2025, see “Compensation Discussion and Analysis - Key Components of Our NEO Compensation Program - Annual Corporate Performance Bonus."

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(3) All amounts reported in this column pertain to the tax-qualified defined benefit pension plan and the supplemental nonqualified, noncontributory retirement plan maintained by the Company. None of the income on nonqualified deferred compensation was above-market or preferential. Variations in the amounts from year to year reflect an additional year of service and pay changes used in the accrued benefit, as well as changes in assumptions on which the benefits are calculated, for which the formula has not been materially revised. The discount rate used for the present value of accumulated benefits was 5.24% for 2023, 5.76% for 2024 and 5.58% for 2025. As of December 31, 2025, the cash balance interest crediting rate assumption changed from 4.04% for 2025 and 4.50% in all future years to 4.74% in 2026 and 5.00% in all future years.

(4) All Other Compensation includes amounts for auto allowance, financial, estate and legal planning, income tax return preparation, annual physical, club memberships, relocation expenses, personal liability insurance, personal use of Company aircraft and for other benefits such as Company contributions on behalf of the NEOs pursuant to the matching component of the Savings and Investment Plan. Perquisites have been valued for purposes of these tables on the basis of the aggregate incremental cost to the Company. The incremental cost of the personal use of the Company aircraft was determined based upon the Company’s expenses incurred in connection with the actual costs of maintenance, landing, parking, crew and catering and estimated fuel costs relating to the hours of use of the aircraft. Fuel expense was determined by calculating the average fuel cost for the month and the average amount of fuel used per hour. These benefits and perquisites for 2025, 2024 and 2023 are itemized in the table below.


Name	Year	401(k) Match		Personal Use of Company Aircraft		Relocation Expenses		Other Benefits		Total
Linda H. Apsey, CEO	2025	$	21,000	$	109,063	$	—	$	29,500	$	159,563
	2024	20,700		72,964		—		31,385		125,049
	2023	19,800		92,049		—		27,185		139,034
										—
Gretchen L. Holloway, SVP & CFO	2025	21,000		—		—		21,599		42,599
	2024	20,700		—		—		21,449		42,149
	2023	19,800		—		—		21,260		41,060
										—
Brian Slocum, SVP & COO	2025	21,000		—		—		22,000		43,000
	2024	20,176		—		—		21,327		41,503
	2023	19,800		—		—		21,171		40,971
										—
Christine Mason Soneral, SVP, General Counsel, Secretary & CCO	2025	21,000		—		—		22,000		43,000
	2024	20,700		—		—		21,789		42,489
	2023	19,800		—		—		20,500		40,300
										—
Krista Tanner, President	2025	21,000		3,331				23,420		47,751
	2024	18,785		—		34,254		21,434		74,473
	2023	16,317		—		—		45,297		61,614

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Grants of Plan-Based Awards

The following table sets forth information concerning each grant of an award made to a NEO during 2025.


Name	Grant Date	Committee or Board Action Date	Award Type	Estimated Future Payouts Under Non-Equity Incentive Plan Awards						Estimated Future Payouts Under Equity Incentive Plan Awards			All Other Stock Awards: Number of Shares of Stock or Units (#)	Grant Date Fair Value of Stock and Option Awards ($)(3)
				Threshold ($)		Target ($)(1)		Maximum ($)(1)		Threshold (#)(2)	Target (#)(2)	Maximum (#)(2)
(a)	(b)			(c)		(d)		(e)		(f)	(g)	(h)	(i)	(j)
Linda H. Apsey	1/1/2025	2/3/2025	SBU	$	—	$	—	$	—	—	—	—	19,447	$	811,167
	1/1/2025	2/3/2025	PBU	—		—		—		19,447	38,895	77,789	—	1,622,333
			ACPB	—		973,400		1,946,800		—	—	—	—	—

Gretchen L. Holloway	1/1/2025	2/3/2025	SBU	—		—		—		—	—	—	6,449	268,975
	1/1/2025	2/3/2025	PBU	—		—		—		6,449	12,897	25,794	—	537,950

			ACPB	—		461,100		922,200		—	—	—	—	—

Brian Slocum	1/1/2025	2/3/2025	SBU	—		—		—		—	—	—	6,460	269,450
	1/1/2025	2/3/2025	PBU	—		—		—		6,460	12,920	25,840	—	538,900
			ACPB	—		404,175		808,350		—	—	—	—	—

Christine Mason Soneral	1/1/2025	2/3/2025	SBU	—		—		—		—	—	—	6,321	263,667
	1/1/2025	2/3/2025	PBU	—		—		—		6,321	12,643	25,285	—	527,333
			ACPB	—		452,000		904,000		—	—	—	—	—

Krista Tanner	1/1/2025	2/3/2025	SBU	—		—		—		—	—	—	8,226	343,113
	1/1/2025	2/3/2025	PBU	—		—		—		8,226	16,452	32,904	—	686,227
			ACPB	—		556,400		1,112,800		—	—	—	—	—

____________________________

(1) The amount shown in Column (d) represents the potential payout for the ACPB based on “target bonus levels.” The amount payable assuming maximum achievement of all bonus goals, including the bonus multiplier, is set forth in column (e). Actual dollar amounts paid are disclosed and reported in the “Summary Compensation Table” as Non-Equity Incentive Plan Compensation. For more information regarding the ACPBs, see “Compensation Discussion and Analysis — Key Components of Our NEO Compensation Program — Annual Corporate Performance Bonus.”

(2) Payment of each PBU award is contingent on meeting performance targets based on (1) Fortis TSR in comparison to the TSR during the performance period for each of the companies that comprise the 2025 Fortis peer group, (2) cumulative consolidated net income for each fiscal year during the performance period and (3) Fortis’ climate-related goals during the performance period. The performance measures are independent of each other. If threshold, target or maximum performance goals are attained in the performance period, 50%, 100% or 200% of the target amount, respectively, may be earned. If actual performance falls between threshold, target and maximum, the awards would be prorated between levels based on performance outcome. For more information regarding PBUs, see “Grant of Plan-Based Awards - Performance-Based Unit Award Agreements.”

(3) Grant Date Fair Value consists of SBUs and PBUs awarded under the Fortis Inc. Omnibus Equity Plan recorded at fair value at the date of grant. The SBUs and PBUs with a grant date of January 1, 2025 are recorded with a fair value of $41.71 per share.

Performance-Based Unit Award Agreements

The PBU award agreements entered into with each NEO effective January 1, 2025 (the “PBU Grant Date”) (each a “PBU Agreement”) provide generally that the award will vest on January 1, 2028 (the “PBU Vesting Date”) to the extent one or more of the performance goals are met and if the grantee continues to be employed by the Company through the PBU Vesting Date. 45% of the Target Number of PBUs shall be related to the Fortis TSR goal (the “TSR goal”), 45% of the Target Number of PBUs shall be related to the Cumulative Consolidated Net Income goal (the “CCNI goal”) and 10% of the Target Number of PBUs shall be related to the

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Fortis Climate-Related Performance Measure (the “CLM goal”). The PBUs will become earned as set forth in the following tables:

Measurement Category

Goal at Threshold

Shares at Threshold

Goal at Target

Shares at Target

Goal at Maximum

Shares at Maximum

Fortis TSR

30th percentile

50% of TSR Target Units

50th percentile

100% of TSR Target Units

85th percentile

200% of TSR Target Units

Cumulative Consolidated Net Income

98% of Target

50% of CCNI Target Units

100% of Target

100% of CCNI Target Units

104% of Target

200% of CCNI Target Units

Fortis Climate-Related Performance Measure

Advance climate adaptation and mitigation activities

50% of CLM Target Units

Threshold performance and advance actions to support reduction of GHG emissions

100% of CLM Target Units

Target performance and achievement of forecast climate-related metrics

200% of CLM Target Units

The performance period for the award is January 1, 2025 through December 31, 2027 (the “Payment Criteria Period”). The performance measures are independent of each other; that is, if the threshold level of one performance measure is attained, units relating to that measure will be “earned” (subject to vesting as otherwise provided in the PBU Agreement) even if the threshold level of the other performance measure is not attained. The number of PBUs that are “earned” with respect to each performance measure will be prorated between levels based on performance. The Committee will have discretion to reduce the number of PBUs earned under certain circumstances.

Fortis TSR will be compared to each of the companies (the “Peer Companies”) listed in the Fortis Peer Group 2025 Report excluding any company that is no longer traded on the Toronto Stock Exchange or a “national securities exchange” at the end of the Payment Criteria Period. The Peer Companies currently consist of the following U.S. and Canadian public utility companies:


Alliant Energy Corporation	Emera Incorporated	PPL Corporation
Ameren Corporation	Enbridge Inc.	Public Service Enterprise Group Inc.
Atmos Energy Corporation	Entergy Corporation	TC Energy Corporation
Canadian Utilities Limited	Evergy, Inc.	WEC Energy Group, Inc.
CenterPoint Energy Inc.	Eversource Energy	Xcel Energy Inc.
CMS Energy Corporation	FirstEnergy Corp.
Consolidated Edison Inc.	Hydro One Limited
DTE Energy Company	NiSource Inc.
Edison International	Pinnacle West Capital Corporation

Fortis TSR shall be computed for the Payment Criteria Period and compared to the Peer Companies for the same period. Fortis’ TSR percentile rank relative to the Peer Companies will establish the TSR performance. If Fortis’ TSR performance is within the minimum and maximum payout thresholds, linear interpolation will be used to determine the percentage payout, such percentage being between 50% and 200%.

Adjusted Consolidated Net Income for the Company for each calendar year in the Payment Criteria Period shall be equal to net income as set forth in the Company’s audited consolidated financial statements contained in its annual report on Form 10-K for such year, as adjusted for extraordinary items and changes in Return on Equity, in each case at the Committee’s discretion. Cumulative Consolidated Net Income for the Company during the Payment Criteria Period shall be the sum of the Adjusted Consolidated Net Income for each of the three years in the Payment Criteria Period. See “Compensation Discussion and Analysis - Key Components of Our NEO Compensation Program - Annual Corporate Performance Bonus" for a reconciliation of Adjusted Consolidated Net Income to Net Income.

The Fortis CLM goal will evaluate the targets linked to Fortis’ achievement of initiatives to advance climate adaptation and support reduction in GHG emissions enterprise-wide over the Payment Criteria Period.

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If the grantee ceases to be employed before the PBU Vesting Date due to death, disability or “Retirement” (as defined below), and, in each case, the grantee has been employed with the Company for 15 years or more, the grantee will receive, following the PBU Vesting Date, the number of PBUs to which the grantee would have otherwise been entitled if the grantee had remained employed through the PBU Vesting Date. If the grantee ceases to be employed before the PBU Vesting Date due to death, disability or Retirement, and the grantee has been employed with the Company for less than 15 years, the grantee will receive, following the PBU Vesting Date, a prorated number of PBUs reflecting the actual period between the PBU Grant Date and the grantee’s termination date. If the grantee ceases to be employed before the PBU Vesting Date due to involuntary termination without cause, the grantee will receive, following the PBU Vesting Date, a prorated number of PBUs reflecting the actual period between the PBU Grant Date and the grantee’s termination date, but will not be entitled to continue to accrue “dividend equivalents” earned on the PBUs following the grantee’s termination date. If termination occurs prior to the PBU Vesting Date other than as a result of death, disability, Retirement, or involuntary termination without cause, the grantee will forfeit the award.

“Retirement” is defined to mean termination of the grantee’s employment with the Company on or after achieving at least age 55 and ten (10) years of service. Payout in respect of such termination requires that the grantee has provided the Company with at least ninety days’ written notice of such retirement.

Upon a “Change of Control,” as defined in the Fortis Inc. Omnibus Equity Plan, the Fortis Human Resources Committee may provide for appropriate settlements of the outstanding PBUs or for the continuing entity or successor to assume the outstanding PBUs by providing replacement awards (“Replacement Awards”), that are substantially equivalent to the terms of the PBUs held prior to the Change in Control, on the effective date of the consummation of the event resulting in the Change of Control (the “Change of Control Redemption Date”). Among other requirements, the Replacement Awards must be substantially equivalent to the value and terms of the PBUs held prior to the Change of Control and must include conditions that provide for vesting and payout if there is an involuntary employment action that occurs within 24 months following the Change of Control. In the event of a Change of Control and an involuntary employment action (which includes a resignation by the grantee for good reason) that occurs within 24 months following a Change of Control, the payout percentage for the Replacement Awards should be calculated as the greater of (i) target level performance and (ii) the actual performance level achieved had the Payment Criteria Period ended on the involuntary employment action date. In the event of a Change of Control and the PBUs are settled and not substituted with Replacement Awards, the PBUs will payout on the date of the Change of Control based on the market price as of the date immediately prior to the Change of Control. The payout percentage for the outstanding PBUs will be the greater of (A) 100% of the target number of PBUs in the award or (B) the payout percentage as determined by the Committee.

Grantees are entitled to receive additional PBUs equal to the “dividend equivalent” when a cash dividend is paid on Common Shares. Such “dividend equivalent” shall be equal to a fraction where the numerator is the product of (a) the number of PBUs in the grantee’s account on the date that the dividends are paid, including PBUs previously credited as “dividend equivalents,” multiplied by (b) the dividend paid per Common Share and the denominator of which is the “Market Price” of one Common Share calculated on the date that dividends are paid. All “dividend equivalent” PBUs shall have a PBU Vesting Date which is the same as the PBU Vesting Date for the PBUs in respect of which such additional PBUs are credited.

The PBU Agreement provides that the grantee may elect to have their PBU awards vest as Common Shares or cash payment.

Service-Based Unit Award Agreements

The SBU award agreements entered into with each NEO on January 1, 2025 (the “SBU Grant Date”) (each a “SBU Agreement”) provide generally that, so long as the grantee remains employed by the Company, the SBUs fully vest on January 1, 2028 (the “SBU Vesting Date”). However, if the grantee ceases to be employed before the SBU Vesting Date due to death, disability or Retirement, and, in each case, the grantee has been employed with the Company for 15 years or more, the grantee will receive, the number of SBUs to which the grantee would have otherwise been entitled if the grantee had remained employed through the SBU Vesting Date, with, in the case of the grantee’s death or disability, the SBUs being settled upon the date of the grantee’s termination of employment and, in the case of the grantee’s Retirement, the SBUs being settled on the SBU Vesting Date. If the grantee ceases to be employed before the SBU Vesting Date due to death, disability or Retirement, and, in each case, the grantee has been employed with the Company for less than 15 years, the grantee will receive a prorated number of SBUs to reflect the actual period between the SBU Grant Date and the date of the grantee’s

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death, disability or Retirement, with, in the case of the grantee’s death or disability, the SBUs being settled upon the date of the grantee’s termination of employment and, in the case of the grantee’s Retirement, the SBUs being settled on the SBU Vesting Date. If the grantee ceases to be employed before the SBU Vesting Date due to involuntary termination without cause, the grantee will receive, following the SBU Vesting Date, a prorated number of SBUs reflecting the actual period between the SBU Grant Date and the grantee’s termination date, but will not be entitled to continue to accrue “dividend equivalents” earned on the SBU shares following the grantee’s termination date. If termination occurs prior to the SBU Vesting Date other than as a result of death, disability, Retirement or involuntary termination without cause, the grantee will forfeit the award.

“Retirement” is defined in the same manner as defined in the description of the PBU Agreement disclosed above.

Upon a “Change of Control,” as defined in the Fortis Inc. Omnibus Equity Plan, the Fortis Human Resources Committee may provide for appropriate settlements of the outstanding SBUs or for the continuing entity or successor to assume the outstanding SBUs by providing Replacement Awards that are substantially equivalent to the terms of the SBUs held prior to the Change in Control, on the effective date of the consummation of the event resulting in the Change of Control. The Replacement Awards must be substantially equivalent to the value and terms of the SBUs held prior to the Change of Control and must include conditions that provide for vesting and payout if there is an involuntary employment action that occurs within 24 months following the Change of Control. In the event of a Change of Control and an involuntary employment action that occurs within 24 months following a Change of Control, the Replacement Awards should payout no later than 10 business days following the involuntary employment action date. In the event of a Change of Control and the SBUs are settled and not substituted with Replacement Awards, the SBU shares become vested and payout on the date of the Change of Control based on the market price as of the date immediately prior to the Change of Control.

Grantees are entitled to receive additional SBUs equal to the “dividend equivalent” when a cash dividend is paid on Common Shares. Such “dividend equivalent” shall be equal to a fraction where the numerator is the product of (a) the number of unvested SBUs in the grantee’s account on the date that the dividends are paid, including SBUs previously credited as “dividend equivalents,” multiplied by (b) the dividend paid per Common Share and the denominator of which is the “Market Price” of one Common Share calculated on the date that dividends are paid. All “dividend equivalent” SBUs shall have a SBU Vesting Date which is the same as the SBU Vesting Date for the SBUs in respect of which such additional SBUs are credited.

The SBU Agreement provides that the grantee may elect to have their SBU awards vest as Common Shares or cash payment.

Policies and Practices Related to the Grant of Option Awards

We do not grant equity awards in anticipation of the release of material nonpublic information, and we do not time the release of material nonpublic information based on grant dates or for the purpose of affecting the value of executive compensation. In addition, we do not take material nonpublic information into account when determining the timing and terms of grants. Although we do not have a formal policy with respect to the timing of option grants, the Committee has historically recommended to the Fortis Board of Directors the grant of equity awards on a predetermined annual schedule. We do not have the authority to grant option awards. Accordingly, in 2025, we did not grant new awards of stock options, stock appreciation rights, or similar option-like instruments to our NEOs.

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Outstanding Equity Awards at Fiscal Year-End

The following table provides information with respect to SBUs and PBUs that have not vested as of the end of 2025 held by the NEOs. For presentation purposes, fractional units have been rounded to the nearest whole unit.


Name	Number of Shares or Units of Stock That Have Not Vested (#)		Market Value of Shares or Units of Stock That Have Not Vested ($) (1)		Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#) (PBUs)		Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($) (PBUs) (1)
(a)	(b)		(c)		(d)		(e)
Linda H. Apsey	20,936	(2)	$	1,087,398	—		$	—
	59,876	(3)	3,109,936		—		—
	20,627	(4)	1,071,382		82,509	(5)	4,285,529
	20,172	(6)	1,047,752		80,689	(7)	4,191,008

Gretchen L. Holloway	7,078	(2)	367,649		—		—
	20,245	(3)	1,051,509		—		—
	6,906	(4)	358,718		27,626	(5)	1,434,874
	15,406	(8)	800,238		—		—
	6,689	(6)	347,424		26,756	(7)	1,389,697

Brian Slocum	5,549	(2)	288,233		—		—
	15,872	(3)	824,375		—		—
	5,783	(4)	300,372		23,132	(5)	1,201,486
	6,701	(6)	348,038		26,803	(7)	1,392,151

Christine Mason Soneral	6,806	(2)	353,525		—		—
	19,467	(3)	1,011,101		—		—
	6,641	(4)	344,937		27,228	(5)	1,379,748
	6,557	(6)	340,568		26,228	(7)	1,362,271

Krista Tanner	6,341	(2)	329,337		—		—
	18,135	(3)	941,916		—		—
	6,727	(4)	349,424		26,910	(5)	1,397,696
	8,533	(6)	443,186		34,131	(7)	1,772,744

____________________________

(1)Value was determined by multiplying the number of units that have not vested by the closing price of Common Shares on the NYSE as of December 31, 2025 ($51.94).

(2)These unvested SBUs were granted in 2023 and vested on January 1, 2026. These SBU numbers include the original SBU grant plus dividend equivalent units earned.

(3)These unvested PBUs were granted in 2023 and earned with respect to the applicable performance measures during the three-year performance period started January 1, 2023 and ended December 31, 2025. These PBU numbers include the original grant plus dividend equivalent units earned, and the performance achievement of 143%. Such PBUs vested on January 1, 2026, and the Committee certified the achievement of the applicable performance goals on February 2, 2026.

(4)These unvested SBUs were granted in 2024 and vest on January 1, 2027. These SBU numbers include the original SBU grant plus dividend equivalent units earned.

(5)These unvested PBUs were granted in 2024 and generally vest on January 1, 2027. These PBU numbers include the original PBU grant plus dividend equivalent units earned. The award contains performance conditions established by the Committee. In order for PBUs to vest such performance conditions must be achieved. Amounts reported reflect PBU payouts as if the maximum performance goals have been achieved.

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(6)These unvested SBUs were granted in 2025 and generally vest on January 1, 2028. These SBU numbers include the original SBU grant plus dividend equivalent units earned.

(7)These unvested PBUs were granted in 2025 and generally vest on January 1, 2028. These PBU numbers include the original PBU grant plus dividend equivalent units earned. The award contains performance conditions established by the Committee. In order for PBUs to vest such performance conditions must be achieved. Amounts reported reflect PBU payouts as if the maximum performance goals have been achieved.

(8)These unvested SBUs were granted in 2024 and vest on August 1, 2027 and August 1, 2028. These SBU numbers include the original grant plus dividend equivalent units earned.

The 2023 PBU grants made to NEOs were made pursuant to the Executive Omnibus Plan and the 2023 SBU grants made to NEOs were made pursuant to the Fortis Inc. 2020 Restricted Share Unit Plan. The 2024 and 2025 PBU and SBU grants made to NEOs were made pursuant to the Fortis Inc. Omnibus Equity Plan. The terms of the grants are described above in the narrative discussion accompanying the “Grants of Plan-Based Awards” Table.

Stock Vested

The following table provides information with respect to SBUs and PBUs held by the NEOs that vested during 2025:


Stock Awards
Name	Number of Shares or Units of Stock Acquired on Vesting (#)		Value of Shares or Units of Stock Realized on Vesting ($) (1)
(a)	(b)		(c)
Linda H. Apsey	16,882	(2)	$	799,429
	29,373	(3)	1,390,950

Gretchen L. Holloway	5,765	(2)	273,007
	10,031	(3)	475,023

Brian Slocum	4,372	(2)	207,020
	7,607	(3)	360,207

Christine Mason Soneral	5,598	(2)	265,115
	9,741	(3)	461,264

Krista Tanner	5,065	(2)	239,833
	8,816	(3)	417,476

____________________________

(1)Value is based on the 5-day volume weighted average price of common stock on the Toronto Stock Exchange on the vesting date, converted from Canadian Dollars to US Dollars using the “Applicable Exchange Rate” defined in the Executive Omnibus Plan and Fortis Inc. 2020 Restricted Share Unit Plan, which was $47.35.

(2)Amounts reported reflect the vesting of SBUs granted January 1, 2022 and associated dividend equivalent units.

(3)Amounts reported reflect the vesting of PBUs granted January 1, 2022 and associated dividend equivalent units. The award contains performance conditions established by the Committee. The performance period ended on December 31, 2024. The Committee certified the achievement of 87% of the applicable performance goals on February 4, 2025.

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Pension Benefits

The following table provides information with respect to each pension benefit plan that provides for payments or other benefits at, following or in connection with retirement. Those plans are the International Transmission Company Retirement Plan (the “Qualified Plan”) and the ESRP.

Pension Benefits Table

Name

Plan Name

Number of Years Credited Service (#)(1)

Present Value of Accumulated Benefit ($)(2)

Payments During Last Fiscal Year ($)

(a)

(b)

(c)

(d)

(e)

Linda H. Apsey

Cash Balance Component

31.59

625,683

N/A

ESRP Shift

N/A

42,546

N/A

Total Qualified Plan

668,229

N/A

ESRP

22.83

3,368,665

N/A

Gretchen L. Holloway

Cash Balance Component

21.95

442,393

N/A

Total Qualified Plan

442,393

N/A

ESRP

10.91

917,192

N/A

Brian Slocum

Cash Balance Component

22.56

443,583

N/A

Total Qualified Plan

443,583

N/A

ESRP

14.91

763,769

N/A

Christine Mason Soneral

Cash Balance Component

18.29

446,191

N/A

Total Qualified Plan

446,191

N/A

ESRP

18.29

1,338,210

N/A

Krista Tanner

Cash Balance Component

11.14

254,981

N/A

Total Qualified Plan

254,981

N/A

ESRP

11.14

765,670

N/A

____________________________

(1) Credited service is estimated as of December 31, 2025 and represents the service reflected in the determination of benefits. For determining vesting, service with DTE Energy is counted for the Qualified Plan only.

For Ms. Apsey, the credited service for the cash balance component of the Qualified Plan, includes service with DTE Energy. The Company began operations on February 28, 2003, following its acquisition of ITCTransmission from DTE Energy. As of that date, the benefits from DTE Energy’s qualified plan that had accrued, as well as the associated assets from DTE Energy’s pension trust, were transferred to the Qualified Plan. Therefore, even though DTE Energy service is included in determining the benefits under the cash balance component of the Qualified Plan, the benefits associated with this additional service do not represent a benefit augmentation, but rather a transfer of benefit liability and associated assets from DTE Energy’s qualified plan to the Qualified Plan. With respect to the ESRP, credited service includes Company service only for the period during which the NEO was an ESRP participant.

(2) The “Present Value of Accumulated Benefit” is the estimated lump-sum equivalent value measured as of December 31, 2025 (the “measurement date” used for financial accounting purposes) of the benefit that was earned as of that date. Certain benefits may not be payable for several years in the future. The values reflected are based on several assumptions. The date at which the present values were estimated was December 31, 2025. The rate at which future expected benefit payments were discounted in calculating present values was 5.58%, the same rate used for fiscal year-end 2025 financial accounting disclosure of the Qualified Plan. The future annual earnings rate on account balances under the cash balance and ESRP shift components of the Qualified Plan, and for ESRP benefits, was assumed to be 4.7% for 2026 and 5.00% thereafter.

We assumed no NEOs would die or become disabled prior to retirement or terminate employment with us prior to benefit commencement. The assumed retirement benefit commencement ages were 58 for each NEO.

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Post-retirement mortality was assumed to be in accordance with the Pri-2012 mortality table projected for future mortality improvements with MP-2020 generational scale. For all other benefits, payment was assumed to be as a single lump sum, although other actuarially equivalent forms are available.

We maintain one tax-qualified noncontributory defined benefit pension plan and one supplemental nonqualified, noncontributory defined benefit retirement plan. First, we maintain the Qualified Plan, which provides funded, tax-qualified benefits up to the limits on compensation and benefits under the Internal Revenue Code. Generally, all of our salaried employees, including the NEOs, are eligible to participate.

We maintain the ESRP, in which all of our NEOs participate. The ESRP provides additional retirement benefits which are not tax qualified.

The following describes the cash balance component of the Qualified Plan and the ESRP, and pension benefits provided to the NEOs under those plans.

Cash Balance Qualified Plan

Benefits under the Qualified Plan are funded by an irrevocable tax-exempt trust. A NEO’s benefit under the Qualified Plan is payable from the assets held by the tax-exempt trust.

NEOs become fully vested in their normal retirement benefits described below with 3 years of service, including service with DTE Energy, or upon attainment of the plan’s normal retirement age of 65. If a NEO terminates employment with less than 3 years of service, the NEO is not vested in any portion of his or her benefit.

Mses. Apsey, Holloway, Mason Soneral and Tanner and Mr. Slocum participate in the Cash Balance Qualified Plan. The benefits are stated as a notional account value.

Each year, a NEO’s account is increased by a “contribution credit” equal to 7% of pay. For this purpose, pay is equal to base salary plus bonuses and overtime up to the compensation limit of the Qualified Plan ($350,000 in 2025). Each year, a NEO’s account is also increased by an “interest credit” based on 30-year Treasury rates.

Upon termination of employment, a vested NEO may elect full payment of his or her account. Alternate forms of benefit (e.g., various forms of annuities) are available as well that have the same actuarial value as the account.

Mses. Apsey, Holloway, Mason Soneral and Tanner and Mr. Slocum are entitled to immediate payment of their account value on termination of employment, even if before normal retirement age. Ms. Apsey’s estimated account value as of year-end 2025 is approximately $634,000, Ms. Holloway’s is approximately $460,000, Mr. Slocum’s is approximately $466,000, Ms. Mason Soneral’s is approximately $460,000, Ms. Tanner’s is approximately $265,000.

The ESRP provides notional account accruals similar to the cash balance component of the Qualified Plan. The “compensation credit” to the NEO’s notional account, analogous to the contribution credit in the cash balance component of the Qualified Plan, is equal to 9% of base salary plus actual bonus earned under the Company’s ACPB plan. The “investment credit,” analogous to the interest credit in the cash balance component of the Qualified Plan, is similarly based on 30-year Treasury rates.

The ESRP shift benefit is an amount that would otherwise be payable from the ESRP, but is instead being paid from the Qualified Plan, subject to applicable qualified plan legal limits on the ability to discriminate in favor of highly paid employees. The NEO’s cash balance account is increased by any amounts shifted from the ESRP. The purpose of the benefit is to provide the NEO and the Company the tax advantages of providing benefits through a tax qualified plan.

Ms. Apsey has received ESRP shift additions to her Qualified Plan cash balance account. There was no shift of compensation credits for 2025, although previous shifts have continued to earn interest credits. As of year-end 2025, her ESRP shift balance was approximately $43,000.

Executive Supplemental Retirement Plan

The ESRP is a nonqualified retirement plan. Only selected executives participate, including all our NEOs. The purpose of the ESRP is to promote the success of the Company and its subsidiaries by providing the ability

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to attract and retain talented executives by providing such designated executives with additional retirement benefits.

The ESRP resembles the cash balance component of the Qualified Plan in that benefits are expressed as a notional account value and the vested account balance is payable as a lump sum on termination of employment, although an installment option of equivalent value is also available.

Each year, a NEO’s account is increased by a “compensation credit” equal to 9% of pay. For this purpose, pay is equal to base salary plus any bonus under the Company’s ACPB plan. There is no limit on compensation that may be taken into account as in the Qualified Plan. Each year, a NEO’s account is also increased by an “investment credit” equal to the same earnings rate as the interest credit in the cash balance component of the Qualified Plan, based on 30-year Treasury rates.

The plan has been in effect since March 1, 2003. Vesting occurs at 20% for each year of participation. All of our NEOs are fully vested.

As noted above in the description of the Qualified Plan, a portion of the ESRP account balance may be shifted to the cash balance component of the Qualified Plan each year, as permitted under the rules for qualified plans. Such a shift allows the NEOs to become immediately vested in the account values shifted and confers certain tax advantages to the NEOs and us. As of December 31, 2025, the ESRP account values, net of the amounts shifted to the Qualified Plan, are as follows:


Ms. Apsey	$	3,414,374
Ms. Holloway	954,678
Mr. Slocum	801,569
Ms. Mason Soneral	1,378,930
Ms. Tanner	794,411

The ESRP is funded with a Rabbi Trust, which we cannot use for any purpose other than to satisfy the benefit obligations under the ESRP, except in the event of the Company’s bankruptcy, in which case the assets are available to general creditors.

Nonqualified Deferred Compensation

We maintain the Executive Deferred Compensation Plan under which nonqualified deferred compensation is permissible. Selected officers of the Company, including the NEOs, are eligible to participate in this plan. NEOs are allowed to defer up to 75% of their salary and 100% of their bonus, and deferral elections may change annually. Investment earnings are based on the various investment options available under the plan and are selected by the individual NEOs (which selections NEOs may change at any time). Distributions will generally be made at the NEO’s termination of employment for any reason. Mr. Slocum enrolled for the 2025 plan year and elected to have 9% of his 2025 salary deferred into the plan. During the enrollment for the 2024 plan year, Mr. Slocum elected to defer 25% of his bonus earned in 2024 and that otherwise would have been paid in 2025. The following table reports amounts contributed in 2025, together with aggregate earnings on contributions and withdrawals or distributions on contributions in 2025, under the plan. For the year ended December 31, 2025, the investment options available under the plan generated annual returns ranging from -0.67% to 31.96%.


Name	Executive Contributions in Last Fiscal Year (1)		Registrant Contributions in Last Fiscal Year		Aggregate Earnings in Last Fiscal Year		Aggregate Withdrawals/Distributions		Aggregate Balance at Last Fiscal Year End (2)
Brian Slocum	$	208,227	$	—	$	276,880	$	—	$	1,700,363

____________________________

(1)The amounts reported in this column for each NEO are reflected as compensation to such NEO in the Summary Compensation Table.

(2)Includes the total market value of deferred compensation program balance at December 31, 2025.

Employment Agreements and Potential Payments Upon Termination or Change in Control

Employment Agreements

As referenced above, we entered into an employment agreement with Ms. Apsey in December 2012 which superseded the employment agreement then in effect. In February 2015, we entered into an employment

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agreement with Ms. Mason Soneral which superseded her employment agreement then in effect. In July 2017, we entered into an employment agreement with Ms. Holloway, which superseded her employment agreement then in effect. In February 2019, we entered into an employment agreement with Ms. Tanner which superseded her employment agreement then in effect. In February 2022, we entered into an employment agreement with Mr. Slocum which superseded his employment agreement then in effect. Each employment agreement is subject to automatic one-year employment term renewals each year beginning on its second anniversary, unless either party provides the other with 30 days’ advance written notice of intent not to renew the employment term. Ms. Apsey’s agreement was modified in October 2016 in connection with her appointment as President and Chief Executive Officer and the initial term of the agreement expired on December 31, 2018 but is subject to the automatic one-year renewal provision described above. The following describes the material terms of the employment agreements, as amended, with the NEOs who remained employed by the Company on December 31, 2025.

The employment agreements provide that each NEO will receive an annual base salary equal to his or her current base salary, which is subject to annual review and increase by our Board of Directors at its discretion. The employment agreements also provide that NEOs are eligible to receive an annual cash bonus, subject to our achievement of certain performance targets established by our Board of Directors, as detailed in “Compensation Discussion and Analysis.” The employment agreements also provide the NEOs with the right to participate in equity plans, employee benefit plans and retirement plans, including but not limited to welfare plans, retiree welfare benefit plans and defined benefit and defined contribution plans.

In addition, the NEOs’ employment agreements provide for payments by us of certain benefits upon termination of employment. The rights available at termination depend on the situation and circumstances surrounding the terminating event. The terms “Cause” and “Good Reason” are used in the employment agreements of each NEO and an understanding of these terms is necessary to determine the appropriate rights for which a NEO is eligible. The terms are defined as follows:

•Cause means: a NEO’s continued failure to substantially perform his or her duties (other than as a result of total or partial incapacity due to physical or mental illness) for a period of 10 days following written notice by the Company to the NEO of such failure; dishonesty in the performance of the NEO’s duties; a NEO’s conviction of, or plea of nolo contendere to, a crime constituting a felony or misdemeanor involving moral turpitude; willful malfeasance or willful misconduct in connection with a NEO’s duties; any act or omission which is injurious to the financial condition or business reputation of the Company; or violation of the non-compete or confidentiality provisions of the employment agreement.

•Good reason means: a greater than 10% reduction in the total value of the NEO’s base salary, target bonus, and employee benefits; or if the NEO’s responsibilities and authority are substantially diminished.

If a NEO’s employment is terminated with cause by the Company or by the NEO without good reason, the NEO will generally only receive his or her accrued but unpaid compensation and benefits as of the date of his or her employment termination. If the NEO terminates due to death or disability (as defined in the employment agreements), the NEO (or the NEO’s spouse or estate) would also receive a pro rata portion of his or her current year annual target bonus.

If a NEO’s employment is terminated by the Company without cause or by the NEO for good reason, the NEO will receive the following, subject to the NEO’s execution of a release agreement and commencing generally on the earliest date that is permitted under Section 409A of the Internal Revenue Code:

•any accrued but unpaid compensation and benefits including:

◦Ms. Apsey: cash balance and ESRP shift under the Qualified Plan and vested portion of ESRP balance; and

◦Ms. Holloway, Mr. Slocum, Ms. Mason Soneral and Ms. Tanner: cash balance under the Qualified Plan and vested portion of ESRP balance;

•continued payment of the NEO’s then-current base salary for two years;

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•if the termination is within six months before or two years after a “Change of Control” (as defined in the employment agreements), payment of an amount equal to two times the average of the ACPBs, that were payable to the NEO for the three fiscal years immediately preceding the fiscal year in which his or her employment terminates, payable in equal installments over the period in which continued base salary payments are made;

•a pro rata portion of the ACPB for the year of termination, based upon the Company’s actual achievement of the performance targets for such year as determined under the ACPB plan and paid at the time that such bonus would normally be paid;

•eligibility to continue coverage under our active medical, dental and vision plans subject to applicable COBRA rules; if such coverage is elected, we will reimburse the NEO for the shorter of 18 months (12 months for Mr. Slocum and Ms. Tanner), or until the NEO becomes eligible for coverage under another employer-sponsored group plan, in an amount equal to our periodic cost of such coverage for other executives, plus a tax gross-up amount;

•outplacement services for up to two years; and

•in addition, if we terminate our Postretirement Welfare Plan and, by application of the provisions described in the prior sentence, any of these NEOs would otherwise be entitled to retiree welfare benefits, we will establish other coverage for the NEO or the NEO will receive a cash payment equal to our cost of providing such benefits, in order to assist the NEO in obtaining other retiree welfare benefits.

In addition, while employed by us and for a period of two years after any termination of employment without cause by the Company (other than due to their disability) or for good reason by them and for a period of one year following any other termination of their employment, the NEOs will be subject to certain covenants not to compete with or assist other entities in competing with our business and not to encourage our employees to terminate their employment with us. At all times while employed and thereafter, all of the NEOs will also be subject to a covenant not to disclose confidential information.

In the event the NEO becomes subject to excise taxes under Section 4999 of the Internal Revenue Code as a result of payments and benefits received under the employment agreements or any other plan, arrangement or agreement with us, we will pay the NEO only that portion of such payments which are in total equal to one dollar less than the amount that would subject the NEO to the excise tax.

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Payments in the Event of Termination

The benefits to be provided to the NEOs as a result of termination under various scenarios are detailed in the tables below. The tables assume that the termination occurred on December 31, 2025.


Linda H. Apsey - Termination Scenarios: Value of Potential Payments
Total Value of Severance, Benefits and Unvested Equity Awards(1)(2)
	Voluntary Resignation		Involuntary For Cause		Involuntary Not-for-Cause or Voluntary Good Reason		Change In Control (pre-tax)(3)		Disability		Death (pre-retirement)(4)
Compensation
Cash Severance	$	—	$	—	$	1,946,800	$	4,659,820	$	—	$	—
Target Short-term Bonus	—		—		—		—		973,400		973,400
Pro Rata Short-term (Annual) Incentive Comp	—		—		1,433,332		1,433,332		—		—
Service-Based Unit Awards (5)	3,206,532		—		3,206,532		3,206,532		3,206,532		3,206,532
Performance-Based Unit Awards (6)	7,348,204		—		7,348,204		7,348,204		7,348,204		7,348,204
Benefits and Outplacement
Retirement Plan	—		—		—		—		—		9,067
ESRP	—		—		—		—		—		45,709
Outplacement	—		—		25,000		25,000		—		—
Health & Welfare Benefits	—		—		109,698		109,698		—		—
Postretirement Welfare Plan (7)	672,689		672,689		672,689		672,689		672,689		—
Total Payout:	$	11,227,425	$	672,689	$	14,742,255	$	17,455,275	$	12,200,825	$	11,582,912


Gretchen L. Holloway - Termination Scenarios: Value of Potential Payments
Total Value of Severance, Benefits and Unvested Equity Awards(1)(2)
	Voluntary Resignation		Involuntary For Cause		Involuntary Not-for-Cause or Voluntary Good Reason		Change In Control (pre-tax)(3)		Disability		Death (pre-retirement)(4)
Compensation
Cash Severance	$	—	$	—	$	922,200	$	2,231,814	$	—	$	—
Target Short-term Bonus	—		—		—		—		461,100		461,100
Pro Rata Short-term (Annual) Incentive Comp	—		—		678,970		678,970		—		—
Service-Based Unit Awards (5)	—		—		1,053,257		1,874,030		1,874,030		1,874,030
Performance-Based Unit Awards (6)	—		—		1,761,416		2,463,794		2,463,794		2,463,794
Benefits and Outplacement
Retirement Plan	—		—		—		—		—		18,081
ESRP	—		—		—		—		—		37,486
Outplacement	—		—		25,000		25,000		—		—
Health & Welfare Benefits	—		—		109,698		109,698		—		—
Total Payout:	$	—	$	—	$	4,550,541	$	7,383,306	$	4,798,924	$	4,854,491

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Brian Slocum - Termination Scenarios: Value of Potential Payments
Total Value of Severance, Benefits and Unvested Equity Awards(1)(2)
	Voluntary Resignation		Involuntary For Cause		Involuntary Not-for-Cause or Voluntary Good Reason		Change In Control (pre-tax)(3)		Disability		Death (pre-retirement)(4)
Compensation
Cash Severance	$	—	$	—	$	1,077,800	$	1,945,004	$	—	$	—
Target Short-term Bonus	—		—		—		—		404,175		404,175
Pro Rata Short-term (Annual) Incentive Comp	—		—		595,148		595,148		—		—
Service-Based Unit Awards (5)	—		—		604,493		936,642		936,642		936,642
Performance-Based Unit Awards (6)	—		—		1,456,896		2,121,194		2,121,194		2,121,194
280G Cutback	—		—		—		(1,023,706)		—		—
Benefits and Outplacement
Retirement Plan	—		—		—		—		—		21,953
ESRP	—		—		—		—		—		37,800
Outplacement	—		—		25,000		25,000		—		—
Health & Welfare Benefits	—		—		73,132		73,132		—		—
Total Payout:	$	—	$	—	$	3,832,469	$	4,672,414	$	3,462,011	$	3,521,764


Christine Mason Soneral - Termination Scenarios: Value of Potential Payments
Total Value of Severance, Benefits and Unvested Equity Awards(1)(2)
	Voluntary Resignation		Involuntary For Cause		Involuntary Not-for-Cause or Voluntary Good Reason		Change In Control (pre-tax)(3)		Disability		Death (pre-retirement)(4)
Compensation
Cash Severance	$	—	$	—	$	904,000	$	2,167,587	$	—	$	—
Target Short-term Bonus	—		—		—		—		452,000		452,000
Pro Rata Short-term (Annual) Incentive Comp	—		—		665,570		665,570		—		—
Service-Based Unit Awards (5)	—		—		697,006		1,039,030		1,039,030		1,039,030
Performance-Based Unit Awards (6)	—		—		1,698,062		2,382,111		2,382,111		2,382,111
Benefits and Outplacement
Retirement Plan	—		—		—		—		—		13,577
ESRP	—		—		—		—		—		40,720
Outplacement	—		—		25,000		25,000		—		—
Health & Welfare Benefits	—		—		109,698		109,698		—		—
Total Payout:	$	—	$	—	$	4,099,336	$	6,388,996	$	3,873,141	$	3,927,438

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Krista Tanner - Termination Scenarios: Value of Potential Payments
Total Value of Severance, Benefits and Unvested Equity Awards(1)(2)
	Voluntary Resignation		Involuntary For Cause		Involuntary Not-for-Cause or Voluntary Good Reason		Change In Control (pre-tax)(3)		Disability		Death (pre-retirement)(4)
Compensation
Cash Severance	$	—	$	—	$	1,112,800	$	2,439,077	$	—	$	—
Target Short-term Bonus	—		—		—		—		556,400		556,400
Pro Rata Short-term (Annual) Incentive Comp	—		—		819,299		819,299		—		—
Service-Based Unit Awards (5)	—		—		710,015		1,121,947		710,015		710,015
Performance-Based Unit Awards (6)	—		—		1,703,271		2,527,135		1,703,271		1,703,271

Benefits and Outplacement
Retirement Plan	—		—		—		—		—		9,571
ESRP	—		—		—		—		—		28,741
Outplacement	—		—		25,000		25,000		—		—
Health & Welfare Benefits	—		—		73,132		73,132		—		—
Total Payout:	$	—	$	—	$	4,443,517	$	7,005,590	$	2,969,686	$	3,007,998

____________________________

(1)Scenarios reflect the value of severance for qualifying terminations. For Ms. Apsey, the value of the Postretirement Welfare Plan is additionally included where applicable. The Pension Benefits Table assumes that none of the NEOs are terminated prior to retirement age and that benefits are paid once retirement commences (age 58 is assumed). All other accrued pension benefits have not been included in these termination scenarios but can be found in the “Pension Benefits Table.” The Nonqualified Deferred Compensation has also not been included in these termination scenarios but can be found in the “Nonqualified Deferred Compensation” section.

(2)Upon any termination of employment, benefits that are accrued but unpaid prior to that event are paid. These benefits are assumed to be $0 in the above tables.

(3)Change in control values include severance amounts reflecting cutbacks to the extent employer payments exceed the executive respective limits. Mr. Slocum would be subject to an excise tax on the employer payments as of the assumed change in control date; therefore, cutbacks in the amount of $1,023,706 (Mr. Slocum) have been reflected.

(4)In the event of termination for death (pre-retirement), the Qualified Plan benefits of Mses. Apsey, Holloway, Mason Soneral and Tanner and Mr. Slocum are payable immediately to the surviving spouse or designated beneficiary if not married and ESRP benefits are payable to a designated beneficiary.

(5)Under the Fortis Inc. 2020 Restricted Share Unit Plan and the Fortis Inc. Omnibus Equity Plan, outstanding and unvested SBUs and respective dividend equivalents shall be deemed to be vested SBUs and redeemable on the date that is immediately prior to the effective date of the consummation of the transaction resulting from the Change of Control if the holder is not granted a Replacement Award. For the SBUs, in the case of Death or Disability termination, outstanding and unvested SBU awards and respective dividend equivalents shall be deemed vested and redeemable on the date of Death or on the date on which the grantee’s service is terminated due to Disability, with the number of SBUs that vest pro-rated to reflect the period of service from grant date to termination if the NEO has less than 15 years of service with the Company or its Affiliates. For the SBUs, in the case of Retirement termination, outstanding and unvested SBU awards and respective dividend equivalents will remain outstanding and shall vest on the SBU Vesting Date, with the number of SBUs that vest on the SBU Vesting Date pro-rated to reflect the period of service from grant date to termination if the NEO has less than 15 years of service with the Company or its Affiliates. For SBU awards, in the case of Involuntary Without Cause termination, the outstanding and unvested SBU awards and respective dividend equivalents shall be deemed to have vested pro-rata based on the period served from grant date to termination and redeemable on the SBU Vesting Date.

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(6)Under the Executive Omnibus Plan and the Fortis Inc. Omnibus Equity Plan, outstanding and unvested PBU awards and respective dividend equivalents shall become redeemable on the Change of Control Redemption Date under a Change in Control if the holder is not granted a Replacement Award. In the case of Death, Disability or Retirement termination and, in each case, 15 years or more of service with the Company or its Affiliates, the outstanding and unvested PBU awards and respective dividend equivalents will remain outstanding and be payable on the payout date of such awards subject to the achievement of the applicable payment criteria. In the case of Death, Disability or Retirement termination and, in each case, less than 15 years of service with the Company or its Affiliates, the outstanding and unvested PBU awards and respective dividend equivalents shall be deemed to have vested pro-rata based on the period served from grant date to termination and redeemable on the PBU Vesting Date. In the case of Involuntary Without Cause termination, the outstanding and unvested PBU awards and respective dividend equivalents shall be deemed to have vested pro-rata based on the period served from grant date to termination and redeemable on the PBU Vesting Date. Values shown in the tables above are based on target performance for the 2024 and 2025 awards as an estimate of potential payments and actual performance of 143% for the 2023 awards.

(7)The value of the Postretirement Welfare Plan benefit is included in all scenarios other than death (pre-retirement) for Ms. Apsey since she has met the retirement eligibility terms of the plan. Postretirement Welfare Benefits is assumed to commence at age 58. The rate at which future expected benefit payments were discounted in calculating the Postretirement Welfare Plan present values was 5.72%, the same rate used for fiscal year-end 2025 accounting disclosure of the Postretirement Welfare Plan.

Upon death or disability, a NEO (or his or her estate) receives a pro rata portion of his or her current year target corporate performance bonus. All balances under the cash balance and ESRP shift components of the Qualified Plan, and the ESRP balance (vested portion only for disability), are immediately payable. If the NEO has 10 years of service after age 45, then the NEO (and his or her spouse) is eligible for retiree medical benefits.

Pay Ratio

As required by the Dodd-Frank Wall Street Reform and Consumer Protection Act, and the SEC under Item 402(u) of Regulation S-K, we are providing the following information about the relationship of the annual total compensation of our employees and the annual total compensation of Linda H. Apsey our CEO:

For 2025, our last completed fiscal year:

the median of the annual total compensation of all employees of the Company (other than Ms. Apsey), was $189,522; and

the annual total compensation of Ms. Apsey as reported in the Summary Compensation Table was $5,509,579.

Based on this information, Ms. Apsey’s 2025 annual total compensation was estimated to be 29 times the median annual total compensation for all employees, other than Ms. Apsey.

We determined that, as of December 31, 2025, our employee population consisted of 868 individuals with all of those individuals located in the United States. To identify the “median employee” from our employee population, excluding Ms. Apsey, we utilized a consistently applied compensation measure that included the sum of each employee’s 2025 annualized base salary as of December 31, 2025 as reflected in our payroll records, and target 2025 awards made under our ACPB plan, 2024 Omnibus Plan and the Fortis Inc. Omnibus Equity Plan that were not paid in 2025. We arrayed these values to select our “median employee.”

Under Item 402(u), a company is permitted to identify its “median employee” once every three years if there has been no significant change to its employee population or employee compensation arrangements that would result in a significant change to its pay ratio disclosure. We updated our “median employee” for 2023 as it had been three years since we had last identified the “median employee” for this analysis.

Although we are permitted to use the same median employee for up to three years, we determined it was appropriate to identify a new median employee for 2025 due to an increase in the number of employees during the year. We concluded that this change could materially impact the comparability of our CEO pay ratio, and therefore re‑identified the median employee for 2025. We intend to use this newly identified median employee

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for the next three years as permitted under Item 402(u), unless we determine in a future period that there have been material changes to our employee population or compensation arrangements that would require us to identify a new median employee sooner.

Using our “median employee” and Ms. Apsey, we calculated the applicable Summary Compensation Table values for each according to applicable SEC rules.

Director Compensation

The following table provides information concerning the compensation of each person who served as a non-employee director of the Company during 2025.

Non-Employee Director Compensation Table


Name	Fees Earned or Paid in Cash ($) (1)		Total ($)
(a)	(b)		(h)
Leanne M. Bell	$	155,000	$	155,000
Diane C. Bridgewater	—		—
Geoffrey S. Chatas	155,000		155,000
Rowena G. Crosbie	—		—
Robert A. Elliott	175,000		175,000
Debora M. Frodl	167,500		167,500
Ronnie D. Hawkins, Jr.	155,000		155,000
David G. Hutchens	155,000		155,000
James P. Laurito	155,000		155,000
Jocelyn H. Perry	155,000		155,000
Sandra E. Pierce	210,000		210,000
Kevin L. Prust	155,000		155,000
A. Douglas Rothwell	162,500		162,500
Brian C. Walker	155,000		155,000

____________________________

(1)Includes annual Board retainer and committee chairmanship retainer, as well as a chairperson fee (for Ms. Pierce only). Ms. Bridgewater and Ms. Crosbie joined the Board in January 2026.

Directors who are employees of the Company do not receive separate compensation for their services as a director. All non-employee directors are compensated under our non-employee director compensation policy, pursuant to which they are paid an annual cash retainer of $155,000. In addition, we pay an additional cash retainer of $20,000 annually to the chair of each Board committee and $55,000 annually to our chairperson. We do not pay per-meeting fees under the policy. Non-employee directors are reimbursed for their out-of-pocket expenses incurred for the performance of their duties as directors.

We maintain a Director Deferred Compensation Plan under which nonqualified deferred compensation is permissible. Only non-employee directors of the Company are eligible to participate in this plan. Directors are allowed to defer up to 100% of their annual board compensation. Investment earnings are based on the various investment options available under the plan and are selected by the individual directors. Distributions will be made when the director ceases to serve on the Board and/or ceases to provide other non-employee consulting services to the Company or any Fortis entity. Mr. Chatas participated in this plan in 2025.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.

The following table sets forth certain information regarding the ownership of our common stock and Fortis’ common stock as of February 1, 2026, except as otherwise indicated, by:

•each of our current directors;

•each of the persons named in the “Summary Compensation Table” under Item 11; and

•all current directors and executive officers as a group.

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The number of shares beneficially owned is determined under rules of the SEC and the information is not necessarily indicative of beneficial ownership for any other purpose. Under such rules, beneficial ownership includes any shares as to which the individual has sole or shared voting power or investment power and also any shares which the individual has the right to acquire on February 1, 2026 or within 60 days thereafter through the exercise of any stock option or other right. Unless otherwise indicated, each holder has sole investment and voting power with respect to the shares set forth in the following table:


Name of Beneficial Owner	Number of Company Shares Beneficially Owned (#)	Percent of Class (%)		Number of Fortis shares Beneficially Owned (#)	Percent of Class (%)
Linda H. Apsey	—	—		53,889		*
Gretchen L. Holloway	—	—		8,903		*
Brian Slocum	—	—		5,200		*
Christine Mason Soneral	—	—		—		—
Krista Tanner	—	—		10,693		*
Simon Whitelocke	—	—		10,161		*
Leanne M. Bell	—	—		—		—
Diane C. Bridgewater	—	—		—		—
Geoffrey S. Chatas	—	—		—		—
Rowena G. Crosbie	—	—		—		—
Robert A. Elliott	—	—		—		—
Debora M. Frodl	—	—		—		—
Ronnie D. Hawkins, Jr.	—	—		—		—
David G. Hutchens	—	—		140,308		*
James P. Laurito	—	—		19,503		*
Jocelyn H. Perry	—	—		121,137		*
Sandra E. Pierce	—	—		—		—
Kevin L. Prust	—	—		500		*
A. Douglas Rothwell	—	—		—		—
Brian C. Walker	—	—		—		—
All current directors and executive officers as a group (20 persons)	—	—	%	370,294		*

* Less than one percent

ITC Investment Holdings, which owns all of our outstanding common stock, is 80.1% owned by FortisUS and 19.9% owned by Eiffel. FortisUS is a wholly-owned subsidiary of Fortis.

At December 31, 2025, there were no securities authorized for issuance under any compensation plans of ITC Holdings.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.

CERTAIN TRANSACTIONS

Pursuant to its charter, the Governance and Human Resources Committee is charged with monitoring and reviewing issues involving independence and potential conflicts of interest with respect to our directors and executive officers. The Committee also determines whether or not a particular relationship serves the best interest of the Company and its shareholder and whether the relationship should be continued or eliminated. In addition, our Code of Conduct and Ethics generally forbids conflicts of interest unless approved by the Board or a designated committee.

Although the Company does not have a written policy with regard to the approval of transactions between the Company and its executive officers and directors, each director and officer must annually submit a form to the General Counsel disclosing his or her conflicts or potential conflicts of interest or certifying that no such conflicts of interest exist. Throughout the year, if any transaction constituting a conflict of interest arises or circumstances otherwise change that would cause a director’s or officer’s annual conflict certification to become

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incorrect, the director or officer must inform the General Counsel of such circumstances. The Committee reviews existing conflicts as well as potential conflicts of interest and determines whether any further action is necessary, such as recommending to the Board whether a director or officer should be requested to offer his or her resignation. Where the Board makes a determination regarding a potential conflict of interest, a majority of the Board (excluding any interested member or members) shall decide upon an appropriate course of action. Additionally, any director or officer who has a question about whether a conflict exists must bring it to the attention of the Company’s General Counsel or Chairperson of the Committee.

DIRECTOR INDEPENDENCE

Based on the absence of any material relationship between them and us, other than their capacities as directors, the Board has determined that Mmes. Bell, Bridgewater, Crosbie, Frodl, and Pierce and Messrs. Elliott, Hawkins, Jr., Laurito, Prust, and Rothwell are “independent” as defined in the Shareholders Agreement. In addition, our Board has determined that, as the committees are currently constituted, a majority of the members of the Audit and Risk Committee are “independent” as required in its charter. None of the directors determined to be independent is or ever has been employed by us.

An independent director under the Shareholders Agreement is a director who meets all of the following requirements: (a) is elected by the shareholders of ITC Investment Holdings; (b) is designated as an independent director by the ITC Investment Holdings’ board and Company Board, or the shareholders of ITC Investment Holdings; (c) is not a director that is nominated by Finn Investment Pte Ltd or any successor or permitted assign thereof and appointed as a member of the ITC Investment Holdings’ board and Company Board in accordance with the Shareholders Agreement; (d) is not and during the three years prior to being designated as an independent director has not been any of the following: (i) a director of FortisUS or any of its affiliates (other than ITC Investment Holdings or the Company); or (ii) an officer or employee of ITC Investment Holdings, the Company, FortisUS or any of their affiliates; and (e) would meet the definition of “independent director” under the NYSE Listed Company Manual if such director were a member of the board of directors of Fortis, FortisUS, ITC Investment Holdings, or the Company (assuming, in the case of FortisUS, ITC Investment Holdings and the Company, that such entities were listed on the NYSE).

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.

The following table provides a summary of the aggregate fees incurred for Deloitte’s services in 2025 and 2024:


	2025		2024
Audit fees (1)	$	2,496,000	$	2,459,000
Audit-related fees (2)	155,000		67,000
Tax fees (3)	17,000		12,000
All other fees (4)	25,000		11,000
Total fees	$	2,693,000	$	2,549,000

____________________________

(1) Audit fees were for professional services rendered for the audit of our consolidated financial statements and internal controls and reviews of the interim consolidated financial statements included in quarterly reports and services that are normally provided by Deloitte in connection with statutory and regulatory filing engagements.

(2) Audit-related fees were for assurance and related services that are reasonably related to the performance of the audit or review of our consolidated financial statements and are not reported under “audit fees.” These services include the audit of our employee benefit plans.

(3) Tax fees were professional services for federal and state tax compliance, tax advice and tax planning.

(4) All other fees were for services other than the services reported above. These services included subscriptions to the Deloitte Accounting Research Tool and attendance at Deloitte sponsored conferences and labs.

The Audit and Risk Committee of the Board of Directors does not consider the provision of the services described above by Deloitte to be incompatible with the maintenance of Deloitte’s independence.

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The Audit and Risk Committee has adopted a pre-approval policy for all audit and non-audit services pursuant to which it pre-approves all audit and non-audit services provided by the independent registered public accounting firm prior to the engagement with respect to such services. To the extent that we need an engagement for audit and/or non-audit services between Audit and Risk Committee meetings, the Audit and Risk Committee chairman is authorized by the Audit and Risk Committee to approve the required engagement on its behalf.

The Audit and Risk Committee approved all of the services performed by Deloitte in 2025 pursuant to the pre-approval policy.

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.


(a)	(1)	Financial Statements:
		Management’s Report on Internal Control over Financial Reporting
		Report of Independent Registered Public Accounting Firm
		Consolidated Statements of Financial Position as of December 31, 2025 and 2024
		Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2025, 2024 and 2023
		Consolidated Statements of Changes in Stockholder's Equity for the Years Ended December 31, 2025, 2024 and 2023
		Consolidated Statements of Cash Flows for the Years Ended December 31, 2025, 2024 and 2023
		Notes to Consolidated Financial Statements
	(2)	Financial Statement Schedules
		Schedule I — Condensed Financial Information of Registrant
		All other schedules for which provision is made in Regulation S-X either (i) are not required under the related instructions or are inapplicable and, therefore, have been omitted, or (ii) the information required is included in the consolidated financial statements or the notes thereto that are a part hereof.
(b)		Exhibit Listing


*						Management contract or compensatory plan or arrangement
**						Filed herewith
***						Management contract or compensatory plan or arrangement filed herewith

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SCHEDULE I — Condensed Financial Information of Registrant

ITC HOLDINGS CORP.

CONDENSED STATEMENTS OF FINANCIAL POSITION (PARENT COMPANY ONLY)


	December 31,
(In millions of USD, except share data)	2025		2024
ASSETS
Current assets
Cash and cash equivalents	$	8	$	16
Accounts receivable from subsidiaries	24		20
Intercompany tax receivable from subsidiaries	11		21


Prepaid and other current assets	7		5
Total current assets	50		62
Other assets
Investment in subsidiaries	7,457		6,872
Deferred income taxes	74		65
Advances to subsidiaries	50		—
Other assets	129		136
Total other assets	7,710		7,073
TOTAL ASSETS	$	7,760	$	7,135
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities


Accrued compensation	$	71	$	57
Accrued interest	34		34

Debt maturing within one year	636		—
Other current liabilities	14		17
Total current liabilities	755		108
Accrued pension and postretirement liabilities	27		39

Long-term debt (net of deferred financing fees and discount of $18 and $22, respectively)	3,483		3,878
Other liabilities	135		113
TOTAL LIABILITIES	4,400		4,138
STOCKHOLDER'S EQUITY
Common Stock, without par value, 235,000,000 shares authorized, 224,203,112 issued and outstanding at December 31, 2025 and 2024	892		892
Retained earnings	2,447		2,077
Accumulated other comprehensive income	21		28
Total stockholder’s equity	3,360		2,997
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	7,760	$	7,135

See notes to condensed financial statements (parent company only).

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SCHEDULE I — Condensed Financial Information of Registrant

ITC HOLDINGS CORP.

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (PARENT COMPANY ONLY)


	Year Ended December 31,
(In millions of USD)	2025		2024		2023
Other (expenses) income, net	$	4	$	13	$	13
General and administrative expense	(33)		(11)		(10)
Taxes other than income taxes	(2)		(1)		—
Interest expense, net	(180)		(175)		(161)


LOSS BEFORE INCOME TAXES	(211)		(174)		(158)
INCOME TAX BENEFIT	(55)		(46)		(29)
LOSS AFTER TAXES	(156)		(128)		(129)
EQUITY IN SUBSIDIARIES’ NET EARNINGS	675		612		592
NET INCOME	519		484		463
OTHER COMPREHENSIVE (LOSS) INCOME
Derivative instruments (net of tax of $(2), $(1) and $1, respectively)	(7)		(1)		2

TOTAL OTHER COMPREHENSIVE (LOSS) INCOME, NET OF TAX	(7)		(1)		2
TOTAL COMPREHENSIVE INCOME	$	512	$	483	$	465

See notes to condensed financial statements (parent company only).

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SCHEDULE I — Condensed Financial Information of Registrant

ITC HOLDINGS CORP.

CONDENSED STATEMENTS OF CASH FLOWS (PARENT COMPANY ONLY)


	Year Ended December 31,
(In millions of USD)	2025		2024		2023
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	519	$	484	$	463
Adjustments to reconcile net income to net cash used in operating activities:
Equity in subsidiaries' earnings	(675)		(612)		(592)
Dividends from subsidiaries	64		60		128
Deferred and other income taxes	(105)		(99)		(90)
Net intercompany tax payments from subsidiaries	98		101		113
Share-based compensation	27		4		6

Other	(1)		(10)		4
Changes in assets and liabilities, exclusive of changes shown separately:
Accounts receivable from subsidiaries	(4)		1		(2)
Intercompany tax receivable from subsidiaries	9		(2)		7
Income tax receivable	(3)		—		—


Accrued compensation	10		(3)		(4)


Other current and non-current assets and liabilities, net	(12)		5		6
Net cash (used in) provided by operating activities	(73)		(71)		39
CASH FLOWS FROM INVESTING ACTIVITIES
Equity contributions to subsidiaries	(154)		(189)		(58)
Return of capital from subsidiaries	181		295		223
Advances to subsidiaries	(50)		—		—

Other	2		4		4
Net cash (used in) provided by investing activities	(21)		110		169
CASH FLOWS FROM FINANCING ACTIVITIES
Issuances of long-term debt, net	—		399		799
Borrowings under revolving credit agreements	73		—		16

Net issuances (repayments) of commercial paper	237		—		(134)
Repayments of long-term debt	—		(400)		(250)
Repayments of revolving credit agreements	(73)		—		(26)


Dividends to ITC Investment Holdings	(149)		(343)		(283)


Other	—		(4)		(7)
Net cash provided by (used in) financing activities	88		(348)		115
NET (DECREASE) INCREASE IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH	(6)		(309)		323
CASH, CASH EQUIVALENTS AND RESTRICTED CASH — Beginning of period	17		326		3
CASH, CASH EQUIVALENTS AND RESTRICTED CASH — End of period	$	11	$	17	$	326

See notes to condensed financial statements (parent company only).

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SCHEDULE I — Condensed Financial Information of Registrant

ITC HOLDINGS CORP.

NOTES TO CONDENSED FINANCIAL STATEMENTS (PARENT COMPANY ONLY)

1. GENERAL

For ITC Holdings Corp.’s (“ITC Holdings,” “we,” “our” and “us”) presentation (parent company only), the investment in subsidiaries is accounted for using the equity method. The condensed parent company financial statements and notes should be read in conjunction with the consolidated financial statements and notes of ITC Holdings appearing in this Annual Report on Form 10-K.

As a holding company with no business operations, ITC Holdings’ assets consist primarily of investments in our subsidiaries. ITC Holdings’ material cash inflows are only from dividends and other payments received from our subsidiaries, the proceeds raised from the sale of debt securities, issuances under our commercial paper program and borrowings under our revolving credit agreement. ITC Holdings may not be able to access cash generated by our subsidiaries in order to fulfill cash commitments. The ability of our subsidiaries to make dividend and other payments to us is subject to the availability of funds after taking into account their respective funding requirements, the terms of their respective indebtedness, the regulations of the FERC under the FPA and applicable state laws. In addition, there are practical limitations on using the net assets of each of our Regulated Operating Subsidiaries as of December 31, 2025 for dividends based on management's intent to maintain the FERC-approved capital structure targeting 60% equity and 40% debt for each of our Regulated Operating Subsidiaries. These net assets are included in Schedule I as the line-item “investment in subsidiaries.” Each of our subsidiaries, however, is legally distinct from us and has no obligation, contingent or otherwise, to make funds available to us.

2. DEBT

As of December 31, 2025, the maturities of our debt outstanding were as follows:


(In millions of USD)
2026	$	637
2027	1,400
2028	—
2029	—
2030	700
2031 and thereafter	1,400
Total	$	4,137

See Note 9 to the consolidated financial statements for additional information on the ITC Holdings Senior Notes, the ITC Holdings Notes, the ITC Holdings revolving credit agreement, the ITC Holdings commercial paper program and the ITC Holdings derivative instruments and hedging activities.

Fixed Rate Debt

Based on the borrowing rates obtained from third party lending institutions currently available for bank loans with similar terms and average maturities from active markets, the fair value of the ITC Holdings long-term debt and debt maturing within one year, excluding borrowings on commercial paper, was $3,917 million and $3,806 million at December 31, 2025 and 2024, respectively. These fair values of the ITC Holdings long-term debt and debt maturing within one year represent Level 2 under the three-tier hierarchy described in Note 12 to the consolidated financial statements. The total book value of the ITC Holdings long-term debt and debt maturing within one year, net of discount and deferred financing fees and excluding borrowings on commercial paper, was $3,883 million and $3,878 million at December 31, 2025 and 2024, respectively.

Other Financial Instruments

The carrying value of other financial instruments included in current assets, including cash and cash equivalents, approximates their fair value due to the short-term nature of these instruments.

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3. RELATED PARTY TRANSACTIONS

We may incur charges from our subsidiaries for general corporate expenses incurred. In addition, we may perform additional services for, or receive additional services from our subsidiaries. These transactions are in the normal course of business and payments for these services are settled through accounts receivable and accounts payable, as necessary. We generally settle our intercompany balances with our affiliates on a net basis monthly.

Periodically, we pay dividends to ITC Investment Holdings as shown in the condensed statements of cash flows. Additionally, we may receive dividends and return of capital from our subsidiaries and may make equity contributions to our subsidiaries as shown in the condensed statements of cash flows.

We are the plan sponsor for a pension plan, other postretirement plans and a defined contribution plan discussed in Note 11 to the consolidated financial statements. The benefits-related expenses recorded by our subsidiaries result from the inclusion of benefit costs as a component of the total charge for services performed by our employees under the cost assignment and allocation methods used by us and our subsidiaries.

We may enter into intercompany loan agreements with our subsidiaries. The total of these intercompany loan advances or repayments is presented as a net cash outflow or inflow from investing activities in the condensed statements of cash flows. On August 1, 2025, we entered into an intercompany loan agreement with METC to advance up to $50 million, with a maturity date of August 1, 2027. As of December 31, 2025, the balance outstanding was $50 million. On January 20, 2026, METC repaid the intercompany loan in full with proceeds from the issuance of Senior Secured Notes on January 14, 2026. We received interest payments of $1 million for the year ended December 31, 2025 associated with this intercompany loan. We received principal and interest payments of $4 million for the year ended December 31, 2023 associated with an intercompany loan. There were no intercompany loans outstanding at December 31, 2024.

Intercompany Tax Sharing Arrangement

We operate under an intercompany tax sharing arrangement with our subsidiaries and as a result may receive or pay income taxes based on their stand-alone company tax positions. The total of these tax payments is presented as a net cash outflow or inflow from operating activities in the condensed statements of cash flows. Other reconciling items between the parent company and the consolidated tax liabilities are presented as deferred and other income taxes in the adjustments to reconcile net income to net cash provided by operating activities.

4. SUPPLEMENTAL FINANCIAL INFORMATION

Reconciliation of Cash, Cash Equivalents and Restricted Cash

The following table provides a reconciliation of cash, cash equivalents and restricted cash reported on the condensed statements of financial position that sum to the total of the same such amounts shown in the condensed statements of cash flows:


	December 31,
(In millions of USD)	2025		2024		2023
Cash and cash equivalents	$	8	$	16	$	325
Restricted cash included in other non-current assets	3		1		1
Total cash, cash equivalents and restricted cash	$	11	$	17	$	326

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Supplementary Cash Flows Information


	Year Ended December 31,
(In millions of USD)	2025		2024		2023
Interest paid	$	182	$	176	$	150
Income taxes paid net of refunds:
Federal income taxes paid to ITC Investment Holdings	43		47		42
Michigan income taxes paid to ITC Investment Holdings	5		6		7
Income taxes paid directly to various state jurisdictions	2		1		—
Total income taxes paid	50		54		49

ITEM 16. FORM 10-K SUMMARY.

Not applicable.

128

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on February 11, 2026.


ITC HOLDINGS CORP.
By:			/s/ LINDA H. APSEY
			Linda H. Apsey
			Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.


Signature	Title	Date

/s/ LINDA H. APSEY	Chief Executive Officer	February 11, 2026
Linda H. Apsey	(principal executive officer)

/s/ GRETCHEN L. HOLLOWAY	Senior Vice President and Chief Financial Officer	February 11, 2026
Gretchen L. Holloway	(principal financial and accounting officer)

/s/ SANDRA E. PIERCE	Director and Chairman	February 11, 2026
Sandra E. Pierce

/s/ LEANNE M. BELL	Director	February 11, 2026
Leanne M. Bell

/s/ DIANE C. BRIDGEWATER	Director	February 11, 2026
Diane C. Bridgewater

/s/ GEOFFREY CHATAS	Director	February 11, 2026
Geoffrey Chatas

/s/ ROWENA CROSBIE	Director	February 11, 2026
Rowena Crosbie

/s/ ROBERT A. ELLIOTT	Director	February 11, 2026
Robert A. Elliott

/s/ DEBORA M. FRODL	Director	February 11, 2026
Debora M. Frodl

/s/ RONNIE D. HAWKINS, JR	Director	February 11, 2026
Ronnie D. Hawkins, Jr

/s/ DAVID G. HUTCHENS	Director	February 11, 2026
David G. Hutchens

/s/ JAMES P. LAURITO	Director	February 11, 2026
James P. Laurito

/s/ JOCELYN H. PERRY	Director	February 11, 2026
Jocelyn H. Perry

/s/ KEVIN L. PRUST	Director	February 11, 2026
Kevin L. Prust

129



/s/ A. DOUGLAS ROTHWELL	Director	February 11, 2026
A. Douglas Rothwell

/s/ BRIAN WALKER	Director	February 11, 2026
Brian Walker

130


		Page
PART I		7
Item 1.	Business	7
Item 1A.	Risk Factors	15
Item 1B.	Unresolved Staff Comments	22
Item 1C.	Cybersecurity	22
Item 2.	Properties	23
Item 3.	Legal Proceedings	24
Item 4.	Mine Safety Disclosures	24

PART II		25
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	25
Item 6.	[Reserved]	25
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	25
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	38
Item 8.	Financial Statements and Supplementary Data	40
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	80
Item 9A.	Controls and Procedures	80
Item 9B.	Other Information	80
Item 9C.	Disclosure Regarding Foreign Jurisdictions That Prevent Inspections	80

PART III		81
Item 10.	Directors, Executive Officers and Corporate Governance	81
Item 11.	Executive Compensation	85
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	113
Item 13.	Certain Relationships and Related Transactions, and Director Independence	114
Item 14.	Principal Accountant Fees and Services	115

PART IV		117
Item 15.	Exhibits and Financial Statement Schedules	117
Item 16.	Form 10-K Summary	128
Signatures		129


Exhibit No.						Description of Exhibit

2.1						Agreement and Plan of Merger, dated as of February 9, 2016, among FortisUS Inc., Element Acquisition Sub Inc., Fortis Inc., and ITC Holdings Corp. (filed with Registrant’s Form 8-K on February 11, 2016)

3.1						Restated Articles of Incorporation of ITC Holdings Corp. (filed with Registrant’s Form 10-Q for the quarter ended September 30, 2016)

**3.2						Twelfth Amended and Restated Bylaws of ITC Holdings Corp.



4.3						Indenture, dated as of July 16, 2003, between ITC Holdings Corp. and BNY Midwest Trust Company, as trustee (filed with Registrant’s Registration Statement on Form S-1, as amended, Reg. No. 333-123657)

4.5						First Mortgage and Deed of Trust, dated as of July 15, 2003, between International Transmission Company and BNY Midwest Trust Company, as trustee (filed with Registrant’s Registration Statement on Form S-1, as amended, Reg. No. 333-123657)

4.6						First Supplemental Indenture, dated as of July 15, 2003, supplementing the First Mortgage and Deed of Trust dated as of July 15, 2003, between International Transmission Company and BNY Midwest Trust Company, as trustee (filed with Registrant’s Registration Statement on Form S-1, as amended, Reg. No. 333-123657)

4.7						Second Supplemental Indenture, dated as of July 15, 2003, supplementing the First Mortgage and Deed of Trust dated as of July 15, 2003, between International Transmission Company and BNY Midwest Trust Company, as trustee (filed with Registrant’s Registration Statement on Form S-1, as amended, Reg. No. 333-123657)

4.8						Amendment to Second Supplemental Indenture, dated as of January 19, 2005, between International Transmission Company and BNY Midwest Trust Company, as trustee (filed with Registrant’s Registration Statement on Form S-1, as amended, Reg. No. 333-123657)

4.9						Second Amendment to Second Supplemental Indenture, dated as of March 24, 2006, between International Transmission Company and The Bank of New York Trust Company, N.A. (as successor to BNY Midwest Trust Company), as trustee (filed with Registrant’s Form 8-K on March 30, 2006)

4.10						Third Supplemental Indenture, dated as of March 28, 2006, supplementing the First Mortgage and Deed of Trust dated as of July 15, 2003, between International Transmission Company and BNY Midwest Trust Company, as trustee (filed with Registrant’s Form 8-K on March 30, 2006)


4.12						Second Supplemental Indenture, dated as of October 10, 2006, supplemental to the Indenture dated as of July 16, 2003, between the Registrant and The Bank of New York Trust Company, N.A., (as successor to BNY Midwest Trust Company, as trustee) (filed with Registrant’s Form 8-K on October 10, 2006)

4.14						First Mortgage Indenture between Michigan Electric Transmission Company, LLC and JPMorgan Chase Bank, dated as of December 10, 2003 (filed with Registrant’s Form 10-Q for the quarter ended September 30, 2006)

4.17						ITC Holdings Corp. Note Purchase Agreement, dated as of September 20, 2007 (filed with Registrant’s Form 10-Q for the quarter ended September 30, 2007)

4.18						Third Supplemental Indenture, dated as of January 24, 2008, supplemental to the Indenture dated as of July 16, 2003, between the Registrant and The Bank of New York Trust Company, N.A. (as successor to BNY Midwest Trust Company), as trustee (filed with Registrant’s Form 8-K on January 25, 2008)

4.19						First Mortgage and Deed of Trust, dated as of January 14, 2008, between ITC Midwest LLC and The Bank of New York Trust Company, N.A., as trustee (filed with Registrant’s Form 8-K on February 1, 2008)

4.20						First Supplemental Indenture, dated as of January 14, 2008, supplemental to the First Mortgage Indenture between ITC Midwest LLC and The Bank of New York Trust Company, N.A., as trustee, First Mortgage and Deed of Trust, dated as of January 14, 2008 (filed with Registrant’s Form 8-K on February 1, 2008)

4.24						Third Supplemental Indenture, dated as of November 25, 2008, between METC and The Bank of New York Mellon Trust Company, N.A. (as successor to JPMorgan Chase Bank, N.A.), as trustee, to the First Mortgage Indenture between Michigan Electric Transmission Company, LLC and JPMorgan Chase Bank, dated as of December 10, 2003 (filed with Registrant’s Form 8-K on December 23, 2008)

4.25						Fourth Supplemental Indenture, dated as of December 11, 2009, between ITC Holdings Corp. and The Bank of New York Mellon Trust Company, N.A. (f.k.a. The Bank of New York Trust Company, N.A., as successor to BNY Midwest Trust Company), as trustee (filed with Registrant’s Form 8-K on December 14, 2009)

4.26						Fourth Supplemental Indenture, dated as of December 10, 2009, between ITC Midwest LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Trust Company, N.A.), as trustee (filed with Registrant’s Form 8-K on December 17, 2009)

4.27						Fifth Supplemental Indenture, dated as of April 20, 2010, between Michigan Electric Transmission Company, LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to JPMorgan Chase Bank), as trustee (filed with Registrant’s Form 8-K on May 10, 2010)

4.28						Third Supplemental Indenture, dated as of December 15, 2008, between ITC Midwest LLC and The Bank of New York Mellon Trust Company, N.A. (The Bank of New York Trust Company, N.A.), as trustee (filed with Registrant’s Form 10-Q for the quarter ended June 30, 2011)

4.29						Fifth Supplemental Indenture, dated as of July 15, 2011, between ITC Midwest LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Trust Company, N.A.), as trustee (filed with Registrant’s Form 10-Q for the quarter ended June 30, 2011)

4.30						Sixth Supplemental Indenture, dated as of November 29, 2011, between ITC Midwest LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Trust Company, N.A.), as trustee (filed with Registrant’s Form 8-K on December 1, 2011)

4.31						Sixth Supplemental Indenture, dated as of October 5, 2012, between Michigan Electric Transmission Company, LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to JPMorgan Chase Bank), as trustee (filed with Registrant’s Form 8-K on October 29, 2012)

4.32						Seventh Supplemental Indenture, dated as of March 18, 2013, between ITC Midwest LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Trust Company, N.A.), as trustee (filed with Registrant’s Form 8-K on April 8, 2013)

4.33						Indenture, dated as of April 18, 2013, between ITC Holdings Corp. and Wells Fargo Bank, National Association, as trustee (including form of note) (filed with Registrant’s Form S-3 on April 18, 2013)

4.34						First Supplemental Indenture, dated as of July 3, 2013, between ITC Holdings Corp. and Wells Fargo Bank, National Association, as trustee (including forms of notes) (filed with Registrant’s Form 8-K on July 3, 2013)

4.35						Fifth Supplemental Indenture, dated as of August 7, 2013, between International Transmission Company and The Bank of New York Mellon Trust Company, N.A. (as successor to BNY Midwest Trust Company), as trustee (including form of bonds) (filed with Registrant’s Form 8-K on August 16, 2013)


4.36						Fifth Supplemental Indenture, dated May 16, 2014, between ITC Holdings Corp. and The Bank of New York Mellon Trust Company, N.A. (f.k.a. The Bank of New York Trust Company, N.A., as successor to BNY Midwest Trust Company), as Trustee (filed with Registrant’s Form 8-K on May 16, 2014)

4.38						Second Supplemental Indenture, dated as of June 4, 2014 between ITC Holdings Corp. and Wells Fargo Bank, National Association, as trustee, together with form of 3.65% Senior Note due 2024 (filed with Registrant’s Form 8-K on June 4, 2014)

4.39						Sixth Supplemental Indenture, dated as of May 23, 2014, between International Transmission Company and The Bank of New York Mellon Trust Company, N.A. (as successor to BNY Midwest Trust Company), as trustee (filed with Registrant’s Form 8-K on June 10, 2014)

4.40						First Mortgage and Deed of Trust, dated as of November 12, 2014, between ITC Great Plains, LLC and Wells Fargo Bank, National Association, as trustee (filed with Registrant’s Form 8-K on November 26, 2014)

4.41						First Supplemental Indenture, dated as of November 12, 2014, between ITC Great Plains, LLC and Wells Fargo Bank, National Association, as trustee (filed with Registrant’s Form 8-K on November 26, 2014)

4.42						Seventh Supplemental Indenture, dated as of December 5, 2014, between Michigan Electric Transmission Company, LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to JPMorgan Chase Bank), as trustee (filed with Registrant’s Form 8-K on December 22, 2014)

4.43						Eighth Supplemental Indenture, dated as of March 18, 2015, between ITC Midwest LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Trust Company, N.A.), as trustee (filed with Registrant’s Form 8-K on April 8, 2015)

4.44						Eighth Supplemental Indenture, dated as of March 31, 2016, between Michigan Electric Transmission Company, LLC and Bank of New York Mellon Trust Company, N.A. (as successor to JPMorgan Chase Bank), as trustee (filed with Registrant’s Form 8-K on April 26, 2016)

4.45						Third Supplemental Indenture, dated as of July 5, 2016, between ITC Holdings Corp. and Wells Fargo Bank, National Association, as trustee, together with form of 3.25% Note due 2026 (filed with Registrant’s Form 8-K on July 5, 2016)

4.46						Ninth Supplemental Indenture, dated as of March 15, 2017, between ITC Midwest LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Trust Company, N.A.), as trustee (filed with Registrant’s Form 8-K on April 18, 2017)

4.47						Fourth Supplemental Indenture, dated as of November 14, 2017 between ITC Holdings Corp. and Wells Fargo Bank, National Association, as trustee (with Form of 2.700% Notes due 2022 and Form of 3.350% Notes due 2027) (filed with Registrant’s Form 8-K on November 15, 2017)

4.48						Seventh Supplemental Indenture, dated as of March 14, 2018, between International Transmission Company and The Bank of New York Mellon Trust Company, N.A. (as successor to BNY Midwest Trust Company), as trustee (filed with Registrant’s Form 8-K on March 29, 2018)

4.49						Tenth Supplemental Indenture, dated as of September 28, 2018, between ITC Midwest LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Trust Company, N.A.) as trustee (filed with Registrant’s Form 8-K on November 2, 2018)

4.50						Ninth Supplemental Indenture, dated as of November 28, 2018, between Michigan Electric Transmission Company, LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to JP Morgan Chase Bank), as trustee (filed with Registrant’s Form 8-K on January 15, 2019)

4.51						Eighth Supplemental Indenture, dated as of August 14, 2019, between International Transmission Company and The Bank of New York Mellon Trust Company, N.A. (as successor to BNY Midwest Trust Company), as trustee (filed with Registrant’s Form 8-K on August 28, 2019)

4.52						Fifth Supplemental Indenture, dated as of May 14, 2020, between ITC Holdings Corp. and Wells Fargo Bank, National Association, as trustee (with Form of 2.95% Notes due 2030) (filed with Registrant’s Form 8-K on May 14, 2020).

4.53						Eleventh Supplemental Indenture, dated as of May 8, 2020, between ITC Midwest LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Trust Company, N.A.) as trustee (filed with Registrant’s Form 8-K on July 15, 2020).

4.54						Tenth Supplemental Indenture, dated as of August 12, 2020, between Michigan Electric Transmission Company, LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to JP Morgan Chase Bank), as trustee (filed with Registrant’s Form 8-K on October 14, 2020).


4.55						Eleventh Supplemental Indenture, dated as of July 19, 2021, between Michigan Electric Transmission Company, LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to JPMorgan Chase Bank), as trustee (filed with Registrant’s Form 8-K on August 3, 2021)

4.56						Ninth Supplemental Indenture, dated as of November 5, 2021, between International Transmission Company and The Bank of New York Mellon Trust Company, N.A. (as successor to BNY Midwest Trust Company), as trustee (including Form of 2.93% First Mortgage Bonds, Series I, due 2052 and Form of 2.93% First Mortgage Bonds, Series J, due 2052) (filed with Registrant’s Form 8-K on January 14, 2022)

4.57						Twelfth Supplemental Indenture, dated as of August 2, 2022, between ITC Midwest LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Trust Company, N.A.) as trustee (including Form of 3.87% First Mortgage Bonds, Series K due 2027 and Form of 4.53% First Mortgage Bonds, Series L due 2052) (filed with Registrant’s Form 8-K on October 12, 2022)

4.58						Sixth Supplemental Indenture, dated as of September 22, 2022, between the Company and Computershare Trust Company, N.A. (as successor to Wells Fargo Bank, National Association), as trustee (with Form of 4.950% Notes due 2027) (filed with the Registrant’s Form 8-K on September 22, 2022)

4.59						Seventh Supplemental Indenture, dated as of June 1, 2023, between the Company and Computershare Trust Company, N.A. (as successor to Wells Fargo Bank, National Association), as trustee (with Form of 5.400% Notes due 2033) (filed with the Registrant’s Form 8-K on June 1, 2023)

4.60						Twelfth Supplemental Indenture, dated as of October 9, 2023, between Michigan Electric Transmission Company, LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to JPMorgan Chase Bank), as trustee (filed with Registrant’s Form 8-K on November 1, 2023)

4.61						Tenth Supplemental Indenture, dated as of December 13, 2023, between International Transmission Company and The Bank of New York Mellon Trust Company, N.A. (as successor to BNY Midwest Trust Company), as trustee (including Form of 5.11% First Mortgage Bonds, Series K, due 2029 and Form of 5.38% First Mortgage Bonds, Series L, due 2034) (filed with the Registrant’s Form 8-K on January 23, 2024)

4.62						Eighth Supplemental Indenture, dated as of May 9, 2024, between the Company and Computershare Trust Company, N.A. (as successor to Wells Fargo Bank, National Association), as trustee (including Form of 5.650% Notes due 2034) (filed with Registrant’s Form 8-K on May 9, 2024)

4.63						Thirteenth Supplemental Indenture, dated as of October 3, 2024, between ITC Midwest LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Trust Company, N.A.), as trustee (filed with Registrant’s Form 8-K on December 10, 2024)

4.64						Thirteenth Supplemental Indenture, dated as of December 16, 2025, between Michigan Electric Transmission Company, LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to JPMorgan Chase Bank), as trustee (filed with Registrant’s Form 8-K on January 14, 2026)

*10.27						Deferred Compensation Plan (filed with Registrant’s Registration Statement on Form S-1, as amended, Reg. No. 333-123657)

10.51						Form of Amended and Restated Easement Agreement between Consumers Energy Company and Michigan Electric Transmission Company (filed with Registrant’s Form 10-Q for the quarter ended September 30, 2006)

*10.81						Executive Supplemental Retirement Plan (filed with Registrant’s Form 10-K for the year ended December 31, 2008)

*10.109						Employment Agreement between ITC Holdings Corp. and Linda H. Blair, effective as of December 21, 2012 (filed with Registrant’s Form 8-K on December 26, 2012)

*10.110						Employment Agreement between ITC Holdings Corp. and Jon E. Jipping, effective as of December 21, 2012 (filed with Registrant’s Form 8-K on December 26, 2012)

*10.111						Employment Agreement between ITC Holdings Corp. and Daniel J. Oginsky, effective as of December 21, 2012 (filed with Registrant’s Form 8-K on December 26, 2012)

*10.120						First Amendment to Executive Supplemental Retirement Plan, dated as of May 16, 2013 (filed with Registrant’s Form 10-Q for the quarter ended June 30, 2013)

*10.122						Recoupment Policy and Related Consent, effective January 1, 2014 (filed with Registrant’s Form 8-K on December 2, 2013)

*10.150						Employment Agreement between ITC Holdings Corp. and Christine Mason Soneral, effective as of February 3, 2015 (filed with Registrant’s Form 10-Q for the quarter ended June 30, 2015)


*10.168						Letter Agreement, dated as of October 14, 2016, between ITC Holdings Corp. and Linda H. Blair (filed with Registrant’s Form 8-K on October 12, 2016)

*10.172						Employment Agreement between ITC Holdings Corp. and Gretchen L. Holloway, effective as of July 10, 2017 (filed with Registrant’s Form 10-K for the year ended December 31, 2020)

*10.173						Letter Agreement, dated as of October 12, 2016 between ITC Holdings Corp. and Christine Mason Soneral (filed with Registrant’s Form 10-K for the year ended December 31, 2016)

*10.176						2017 Omnibus Plan, effective February 27, 2017 (filed with Registrant’s Form 10-Q for the quarter ended March 31, 2017)

*10.177						Summary of 2017 Annual Incentive Plan (filed with Registrant’s Form 10-Q for the quarter ended March 31, 2017)

*10.178						Form of Service-Based Unit Award Agreement under 2017 Omnibus Plan (February 2017) (filed with Registrant’s Form 10-Q for the quarter ended March 31, 2017)

*10.179						Form of Performance-Based Unit Award Agreement under 2017 Omnibus Plan (February 2017) (filed with Registrant’s Form 10-Q for the quarter ended March 31, 2017)

*10.182						Amendment to 2017 Omnibus Plan, dated as of July 10, 2017 (filed with Registrant’s Form 10-Q for the quarter ended June 30, 2017)

*10.183						ITC Holdings Corp. Director Deferred Compensation Plan, effective March 1, 2017 (filed with Registrant’s Form 10-Q for the quarter ended June 30, 2017)

*10.190						International Transmission Company Executive Deferred Compensation Plan, effective January 1, 2019 (filed with Registrant’s Form 10-K for the year ended December 31, 2018)

*10.191						ITC Holdings Corp. Director Deferred Compensation Plan, effective January 1, 2019 (filed with Registrant’s Form 10-K for the year ended December 31, 2018)

*10.192						Letter Agreement, effective as of February 18, 2019, between ITC Holdings Corp. and Jon E. Jipping (filed with Registrant’s Form 8-K on February 22, 2019)

*10.200						2017 Omnibus Plan, as amended July 10, 2017 and February 4, 2020 (filed with Registrant’s Form 10-K for the year ended December 31, 2019)

*10.201						Executive Omnibus Plan, effective February 4, 2020. (filed with Registrant’s Form 10-K for the year ended December 31, 2019)

*10.202						Form of Performance-Based Unit Award Agreement under Executive Omnibus Plan (January 2020). (filed with Registrant’s Form 10-K for the year ended December 31, 2019)

*10.203						Employment Agreement between ITC Holdings Corp. and Krista K. Tanner, effective as of February 18, 2019 (filed with Registrant’s Form 10-K for the year ended December 31, 2021)

*10.204						Fortis Inc. 2020 Restricted Share Unit Plan, effective January 1, 2020 (filed with Registrant’s Form 10-Q for the quarter ended March 31, 2020)

*10.205						Form of Restricted Share Unit Grant Agreement under Fortis Inc. 2020 Restricted Share Unit Plan (January, 2020) (filed with Registrant’s Form 10-Q for the quarter ended March 31, 2020)

*10.206						Separation and Release Agreement, effective as of May 18, 2020, between ITC Holdings Corp. and Daniel J. Oginsky (filed with Registrant’s Form 10-K for the year ended December 31, 2020)

*10.212						Executive Omnibus Plan, as amended November 11, 2021 (filed with Registrant’s Form 10-K for the year ended December 31, 2021)

*10.213						Fortis Inc. 2020 Restricted Share Unit Plan, as amended January 1, 2022 (filed with Registrant’s Form 10-K for the year ended December 31, 2021)

*10.214						Employment Agreement between ITC Holdings Corp. and Brian Slocum, effective as of February 14, 2022 (filed with Registrant’s Form 10-K for the year ended December 31, 2021)

*10.215						Executive Omnibus Plan, as amended January 31, 2023 (effective as of January 1, 2023) (filed with Registrant's Form 10-K for the year ended December 31, 2022)


10.216						Revolving Credit Agreement, dated as of April 14, 2023, among ITC Holdings Corp., ITC Midwest LLC, ITC Great Plains, LLC, Michigan Electric Transmission Company, LLC and International Transmission Company, with the banks, financial institutions and other institutional lenders listed on the respective signature pages thereof, Wells Fargo Bank, National Association, in its capacity as administrative agent, Wells Fargo Securities, LLC, Barclays Bank PLC, JPMorgan Chase Bank, N.A., Mizuho Bank, Ltd. and The Bank of Nova Scotia, as joint lead arrangers and joint bookrunners and Barclays Bank PLC, JPMorgan Chase Bank, N.A., Mizuho Bank, Ltd. and The Bank of Nova Scotia, as co-syndication agents (filed with Registrant’s Form 8-K on April 14, 2023)

*10.217						2024 Omnibus Plan, effective January 1, 2024 (filed with Registrant's Form 10-K for the year ended December 31, 2023)

*10.218						Letter Agreement between ITC Holdings Corp. and Linda H. Apsey, effective as of July 17, 2024 (filed with the Registrant’s 10-Q for the quarter ended September 30, 2024)

*10.219						Employment Agreement between ITC Holdings Corp. and Krista K. Tanner, effective as of July 17, 2024 (filed with the Registrant’s 10-Q for the quarter ended September 30, 2024)

*10.220						Letter Agreement, dated as of August 1, 2024, between ITC Holdings Corp. and Gretchen Holloway (filed with Registrant’s 10-Q for the quarter ended September 30, 2024)

10.221						Amendment No.1 to Revolving Credit Agreement, dated as of December 16, 2024, among ITC Holdings Corp., ITC Midwest LLC, ITC Great Plains, LLC, Michigan Electric Transmission Company, LLC and International Transmission Company, with the banks, financial institutions and other institutional lenders listed on the respective signature pages thereof, and Wells Fargo Bank, National Association, in its capacity as administrative agent. (filed with Registrant's Form 10-K for the year ended December 31, 2024)

***10.222						Letter Agreement, dated as of November 13, 2025, between ITC Holdings Corp. and Krista K. Tanner, effective as of March 23, 2026

19						ITC Holdings Corp. Insider Trading Policies and Procedures (filed with Registrant's Form 10-K for the year ended December 31, 2024)

**21						List of Subsidiaries

**31.1						Certification of Chief Executive Officer pursuant to Rule 13a-14 of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

**31.2						Certification of Chief Financial Officer pursuant to Rule 13a-14 of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

**32						Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

**101.INS						XBRL Instance Document - the instance document does not appear in the Interactive Data file because its XBRL tags are embedded within the Inline XBRL document

**101.SCH						Inline XBRL Taxonomy Extension Schema

**101.CAL						Inline XBRL Taxonomy Extension Calculation Linkbase

**101.DEF						Inline XBRL Taxonomy Extension Definition Database

**101.LAB						Inline XBRL Taxonomy Extension Label Linkbase

**101.PRE						Inline XBRL Taxonomy Extension Presentation Linkbase

**104						The cover page from the Company’s Annual Report on Form 10-K for the year ended December 31, 2025 (formatted in Inline XBRL and contained in Exhibit 101)