ITC

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, 2024
OR
☐
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 
o
o
þ
o
o
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

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
Indicate by check mark whether any of those error corrections are restatements that required a recovery 
analysis of incentive-based compensation received by any of the registrant’s executive officers during the 
relevant recovery period pursuant to §240.10D-1(b).  
 
 
 
 
 
 
      o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). 
  Yes o No þ
The aggregate market value of the registrant’s common stock held by non-affiliates on June 30, 2024 was 
$0.
All shares of outstanding common stock of ITC Holdings Corp. are held by its parent company, ITC 
Investment Holdings Inc., which is an indirect subsidiary of Fortis Inc. There were 224,203,112 shares of the 
registrant’s common stock, no par value, outstanding as of February 13, 2025.
DOCUMENTS INCORPORATED BY REFERENCE
None.
Table of Contents

ITC Holdings Corp.
Form 10-K for the Fiscal Year Ended December 31, 2024 
INDEX
Page
PART I
8
Item 1.
Business
8
Item 1A.
Risk Factors
16
Item 1B.
Unresolved Staff Comments
23
Item 1C.
Cybersecurity
23
Item 2.
Properties
24
Item 3.
Legal Proceedings
25
Item 4.
Mine Safety Disclosures
25
PART II
26
Item 5.
Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases 
of Equity Securities
26
Item 6.
[Reserved]
26
Item 7.
Management's Discussion and Analysis of Financial Condition and Results of Operations
26
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
40
Item 8.
Financial Statements and Supplementary Data
42
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
81
Item 9A.
Controls and Procedures
81
Item 9B.
Other Information
81
Item 9C.
Disclosure Regarding Foreign Jurisdictions That Prevent Inspections
81
PART III
82
Item 10.
Directors, Executive Officers and Corporate Governance
82
Item 11.
Executive Compensation
86
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related 
Stockholder Matters
115
Item 13.
Certain Relationships and Related Transactions, and Director Independence
116
Item 14.
Principal Accountant Fees and Services
117
PART IV
118
Item 15.
Exhibits and Financial Statement Schedules
118
Item 16.
Form 10-K Summary
129
Signatures
130
Table of Contents
3

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 primarily 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
• “2017 Omnibus Plan” are references to the Company’s February 27, 2017 long-term equity incentive plan 
as amended July 10, 2017 and February 4, 2020;
• “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;
Table of Contents
4

• “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;
• “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;
• “Executive Omnibus Plan” are references to the Company’s February 4, 2020 long-term equity incentive 
plan, as amended November 11, 2021 and January 31, 2023 (effective as of January 1, 2023);
• “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;
• “Fortis Inc. 2020 Restricted Share Unit Plan” are references to the Company’s January 1, 2020 long-term 
equity incentive plan, as amended January 1, 2022 and January 1, 2023;
• “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;
• “IRS” are references to the Internal Revenue Service;
• “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;
• “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;
Table of Contents
5

• “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;
• “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;
• “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;
• “Revolving Credit Agreement” are references to the unsecured, unguaranteed revolving credit agreement 
entered into by ITC Holdings, ITCTransmission, METC, ITC Midwest and ITC Great Plains dated as of 
April 14, 2023, which replaced and refinanced in full the previous revolving credit agreements of these 
companies;
• “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 March 6, 2017;
• “TO” are references to transmission owner;
Table of Contents
6

• “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.
Table of Contents
7

PART I
ITEM 1. 
BUSINESS.
Overview
ITC Holdings provides safe and reliable electric transmission service to connect consumers to more 
sustainable and cost-effective energy resources. ITC Holdings continues 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 a cleaner, sustainable and electrified economy, the power grid will need to be 
transformed and modernized. Further, the need for a secure and reliable grid is imperative as we protect critical 
infrastructure and serve as a steward in economic development for 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 required to meet 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 $5.8 billion from 2025 through 2029 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) upgrade physical 
and technological grid security to protect critical infrastructure; (3) expand access to electricity markets to 
reduce the overall cost of delivered energy to customers and provide access to competitive markets for 
economic development; and (4) interconnect new renewable generation resources.
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 
Table of Contents
8

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, System Protection 
and Control and Grid Solutions 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.
Table of Contents
9

The Grid Solutions team is comprised of several groups. The Geographic Information Systems and 
Engineering Data group supports the Engineering group and other functional groups in their use of technical, 
location, and other data. The Environmental group assists with environmental permitting and ongoing permit 
obligations and coordinates other services such as recycling, compliance and environmental planning. The 
Technical Solutions group supports a wide range of technical, business and corporate initiatives.
Safety, Protection and Preparedness
The Safety, Protection and Preparedness group is responsible for safety, human performance, physical 
security, and emergency preparedness and response. Given the inherent hazardous nature of the utilities 
industry, we proactively work to ensure that all personnel are free to perform in a safe and secure environment. 
Our focus is to not compromise the safety of our employees, contractors or the public in the course of providing 
the most reliable electric transmission services. We maintain a safety program that includes proactive measures 
rooted in human performance principles to achieve that focus. Our emergency response plans ensure that we 
are prepared for a crisis and can maintain continuity of our business and service. We operate a security 
command center from our headquarters facility in Michigan that monitors our most critical assets on a 
continuous basis. The security operations center also gathers intelligence and works with our government and 
industry partners to monitor and prevent threats to our assets.
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.
Table of Contents
10

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. 
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 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. METC pays Consumers Energy an annual rent for the easement and also pays for any rentals, 
property taxes and other fees related to the property covered by the Easement Agreement.
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.
Table of Contents
11

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. 
The growth and changing mix of electricity generation, wholesale power sales and consumption combined with 
historically inadequate transmission investment have resulted in significant transmission constraints across the 
United States and increased stress on aging equipment. These problems 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
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. Additionally, we are subject to the 
regulatory oversight of various state environmental quality departments for compliance with any state 
environmental standards and regulations.
Table of Contents
12

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 the Michigan Department of 
Environmental Quality, the Michigan Department of Natural Resources and certain local authorities for 
compliance with all environmental standards and regulations.
ITC Midwest
Iowa
The Iowa Utilities Commission (formerly known as the Iowa Utilities Board) 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 Iowa Utilities 
Commission is vested with the power of condemnation in Iowa to the extent the Iowa Utilities Commission 
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
In 2024, ITC Midwest was declared a “public utility” in the state of 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.
Table of Contents
13

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 
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 does not exercise jurisdiction over the siting of any 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%, 21.9% and 22.7%, respectively, of our consolidated billed revenues for the 
year ended December 31, 2024. 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 
Table of Contents
14

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. 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.
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, 2024, we had 787 employees, with low 
employee turnover and no significant change in the number of employees from the prior year. 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 strive to provide an inclusive environment for all of our 
employees. 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 
Table of Contents
15

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.
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, we may incur expenses related to the pursuit of strategic 
investment opportunities, which may be higher than forecasted.
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 
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;
Table of Contents
16

•
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;
•
the potential for greater competition;
•
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 will depend on obtaining any necessary regulatory and 
other approvals for the project and for us to initiate construction, our achieving status as the builder of the 
project in some circumstances and other factors. In addition, projects may be canceled, the scope of planned 
projects may change, or projects may not be completed on time, any of which may adversely affect our level of 
investment or cause our projected investments to be inaccurate.
In addition, we may incur expenses to pursue strategic investment opportunities. If these payments or 
expenses are higher than anticipated, our future results of operations, cash flows and financial condition could 
be materially and adversely affected.
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.
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, 
Table of Contents
17

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 
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 
Table of Contents
18

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-
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. 
Table of Contents
19

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.
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 
Table of Contents
20

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.
Table of Contents
21

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 
Table of Contents
22

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, 
Table of Contents
23

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 2025 to 2029, 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;
Table of Contents
24

• station assets, such as transformers and circuit breakers, at 707 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.”
Certain of 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.
Table of Contents
25

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 $343 million and $283 million to our parent, ITC Investment Holdings, during 
the years ended December 31, 2024 and 2023, 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 4, 2025, our Board of Directors approved a $72 million dividend to 
ITC Investment Holdings that is expected to be paid on February 27, 2025.
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.
Caution is recommended to not place undue reliance on these forward-looking statements, which 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, 2024 and 2023 and provides year-to-year comparisons 
between the years ended December 31, 2024 and 2023. Discussions of such information for the year ended 
December 31, 2022 and year-to-year comparisons between the years ended December 31, 2023 and 2022 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, 2023.
Table of Contents
26

Overview
ITC Holdings provides safe and reliable electric transmission service to connect consumers to more 
sustainable and cost-effective energy resources. ITC Holdings continues 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 below under “— Cost-
Based Formula Rates with True-Up Mechanism” as well as in Note 6 to the consolidated financial statements.
Significant recent matters that influenced our financial condition, results of operations and cash flows for the 
year ended December 31, 2024 or that may affect future results include:
• Our capital expenditures of $1,062 million at our Regulated Operating Subsidiaries during the year ended 
December 31, 2024, as described below under “— Capital Investment and Operating Results Trends;”
• Debt activity, including derivatives, as described in Note 9 to the consolidated financial statements;
• Rulings from the Iowa Supreme Court and Iowa District Court for Polk County on ROFR proceedings, as 
described below under “ — Recent Developments;”
• The October 2024 Order 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
Rate of Return on Equity Complaints
In 2013 and 2015, complaints were filed with the FERC by combinations of consumer advocates, consumer 
groups, municipal parties and other parties challenging the base ROE for MISO TOs. In response to these 
complaints, the FERC has issued multiple orders to address issues raised in the complaints and subsequent 
proceedings. See Note 17 to the consolidated financial statements for a summary of the MISO ROE Complaints 
and related proceedings.
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 
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. As 
Table of Contents
27

of December 31, 2024, we recorded an aggregate refund liability of $27 million, including interest of $6 million, 
in accordance with the refund provisions of the order.
FERC Order No. 1920
On May 13, 2024, the FERC issued a final rule (“Order 1920”) to reform electric transmission planning and 
cost allocation requirements for transmission providers and introduce federally mandated planning rules for all 
regions (including MISO and SPP) to undertake long-term regional transmission planning efforts on a regular 
basis. The final rule specifies various requirements for the long-term planning process, including the 
consideration of a broad set of benefits for new projects identified through the process and the filing of one or 
more cost allocation methodologies for facilities identified through long-term regional transmission planning. In 
addition, the final rule addresses a number of other aspects of the electric transmission planning process, which 
include:
• Reinstating a ROFR at the federal level for in-kind replacement of existing transmission facilities to 
increase their transfer capability, known as “right-sizing”;
• Mandating the consideration of advanced technologies for long-term regional transmission planning;
• Reforming transmission planning at the local level, including enhancing stakeholder engagement and 
participation;
• Requiring RTOs to address certain needs related to generator interconnections in their planning and cost 
allocation processes; and
• Enhancing interregional transmission coordination procedures among transmission providers in 
neighboring regions.
Order 1920 became effective on August 12, 2024. A number of rehearing requests were filed by various 
parties, including us, requesting the FERC to revise or clarify various aspects of the rule. On November 21, 
2024, the FERC issued an order to address the requests for rehearing, which generally maintains provisions of 
Order 1920 with certain clarifications and modifications. A number of parties have also filed petitions for review 
with various circuit courts, which have been consolidated and assigned to the U.S. Court of Appeals for the 
Fourth Circuit. We will continue to monitor developments related to these challenges while implementing 
processes to address new requirements under the final rule.
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 transmission owners, 
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 Iowa Utilities 
Commission 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 Iowa Utilities Commission 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 has filed for reconsideration of the district court’s 
Table of Contents
28

decision with respect 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 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 total estimated capital investment in Iowa is approximately 
$900 million for the first tranche of MISO’s LRTP, including approximately $800 million in our plan for forecasted 
capital expenditures for the period from 2025 through 2029. Approximately 70% of ITC Midwest’s first tranche of 
MISO’s LRTP projects are upgrades to existing ITC Midwest facilities in Iowa along existing rights of way, which 
under MISO’s tariff grants ITC Midwest the option to construct the upgrades regardless of the outcome of the 
ROFR proceedings. While 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, uncertainty remains around 
the ultimate resolution of these matters.
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.
Table of Contents
29

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, 2024, our Regulated Operating Subsidiaries had a total of 
Table of Contents
30

approximately $6 billion of equity in their collective capital structures for ratemaking purposes. Based on this 
level of aggregate equity, we estimate that each 10 basis point change in the authorized ROE would impact 
annual consolidated net income by approximately $6 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 for incentive adders and base ROE.
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 evaluate 
and monitor the potential impacts of these macroeconomic trends on our forecasted capital expenditures and 
maintenance activities.
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) upgrade 
physical and technological grid security to protect critical infrastructure; (3) expand access to electricity markets 
to reduce the overall cost of delivered energy to customers and provide access to competitive markets for 
economic development; and (4) interconnect new renewable generation resources. 
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-
year plan for forecasted capital expenditures for the years 2025 through 2029.
Table of Contents
31

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, 2024
2025 — 2029
Expenditures for property, plant and equipment (a)
$ 
1,062 $ 
5,837 
____________________________
(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.
After the development of our five-year capital expenditure plan, we identified certain incremental investment 
opportunities that we expect to be additive to our forecasted capital expenditures for the years 2025 through 
2029. However, as of the date of this report, we do not anticipate related capital expenditures will result in a 
material increase to the scope of our overall forecast for this period.
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.
Investments in property, plant and equipment could be lower than expected due to a variety of factors, as 
discussed in “Item 1A. Risk Factors.” In addition, investments in transmission network upgrades for generator 
interconnection projects could change from prior estimates significantly due to changes in the MISO or SPP 
queue for generation projects and other factors beyond our control.
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.
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 
Table of Contents
32

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 return on 
equity at our Regulated Operating Subsidiaries used for construction purposes in accordance with the FERC 
regulations. 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 
return on equity for our Regulated Operating Subsidiaries.
Income Tax Provision
Income tax provision consists of current and deferred federal and state income taxes.
Table of Contents
33

Results of Operations
Year Ended
Percentage
December 31,
Increase
Increase
(In millions of USD)
2024
2023
(Decrease)
(Decrease)
OPERATING REVENUES
Transmission and other services
$ 
1,613 $ 
1,562 $ 
51 
 3 %
Formula Rate true-up
 
12  
(17)  
29 
 171 %
Total operating revenues
 
1,625  
1,545  
80 
 5 %
OPERATING EXPENSES
Operation and maintenance
 
111  
109  
2 
 2 %
General and administrative
 
121  
111  
10 
 9 %
Depreciation and amortization
 
326  
307  
19 
 6 %
Taxes other than income taxes
 
154  
145  
9 
 6 %
Other operating expenses (income), net
 
(1)  
(1)  
— 
 — %
Total operating expenses
 
711  
671  
40 
 6 %
OPERATING INCOME
 
914  
874  
40 
 5 %
OTHER EXPENSES (INCOME)
Interest expense, net
 
348  
315  
33 
 10 %
Allowance for equity funds used during construction
 
(44)  
(43)  
(1) 
 (2) %
Other expenses (income), net
 
(22)  
(17)  
(5) 
 (29) %
Total other expenses (income)
 
282  
255  
27 
 11 %
INCOME BEFORE INCOME TAXES
 
632  
619  
13 
 2 %
INCOME TAX PROVISION
 
148  
156  
(8) 
 (5) %
NET INCOME
$ 
484 $ 
463 $ 
21 
 5 %
Operating Revenues
The following table sets forth the components of and changes in operating revenues for the years ended 
December 31, 2024 and 2023, which included revenue accruals and deferrals as described in Note 6 to the 
consolidated financial statements:
Percentage
 
2024
2023
Increase
Increase
(In millions of USD)
Amount
Percentage
Amount
Percentage
(Decrease)
(Decrease)
Network revenues (a)
$ 
1,175 
 72 % $ 
1,092 
 71 % $ 
83 
 8 %
Regional cost sharing revenues (a)
 
402 
 25 %  
384 
 25 %  
18 
 5 %
Point-to-point
 
21 
 1 %  
19 
 1 %  
2 
 11 %
Scheduling, control and dispatch (a)
 
18 
 1 %  
20 
 1 %  
(2) 
 (10) %
October 2024 Order refund accrual
 
(21) 
 (1) %  
— 
 — %  
(21) 
n/a
Other
 
30 
 2 %  
30 
 2 %  
— 
 — %
Total
$ 
1,625 
 100 % $ 
1,545 
 100 % $ 
80 
 5 %
____________________________
(a) Includes a portion of Formula Rate true-up revenue. 
Operating revenues increased 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. The increase was partially offset by the recognition of the liability for the refund related to the October 
2024 Order. See Note 17 to the consolidated financial statements for additional information.
Table of Contents
34

Other Expenses (Income)
Interest expense, net
Interest expense, net increased for the year ended December 31, 2024 compared to the year ended 
December 31, 2023 primarily due to higher overall debt balances and higher interest rates on long-term debt 
issuances, as well as interest accrued on the refund related to the October 2024 Order, partially offset by a 
reduction of average outstanding balances of commercial paper and revolving credit agreements. See Note 9 to 
the consolidated financial statements for additional information.
Other expenses (income), net
Other expenses (income), net decreased for the year ended December 31, 2024 compared to the year 
ended December 31, 2023 primarily due to an increase in net gains and higher expected returns on higher plan 
assets on certain investments associated with our supplemental benefit plans.
Liquidity and Capital Resources
We expect to maintain our approach of funding our future capital requirements with our cash and cash 
equivalents, including 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.”
• 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 our cash and cash 
equivalents, including cash provided by operations at our Regulated Operating Subsidiaries, our Revolving 
Credit Agreement and long-term debt financing, as needed. In addition, ITC Holdings may use its commercial 
paper program to issue an aggregate amount not to exceed $400 million outstanding at any one time. As of 
December 31, 2024, we had consolidated indebtedness under our Revolving Credit Agreement of $247 million, 
with unused capacity under our Revolving Credit Agreement of $753 million. Additionally, ITC Holdings did not 
have any commercial paper issued and outstanding as of December 31, 2024. In 2024, we paid $18 million of 
interest and commitment fees under our Revolving Credit Agreement.
Table of Contents
35

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, 2024, 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 $4.3 billion as of December 31, 2024, with expected 
interest payment obligations of $336 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 
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, 2024, were as 
follows:
S&P Global Ratings
Moody’s Investor Service, Inc.
Rating
Outlook
Rating
Outlook
ITC Holdings
 Senior Unsecured Notes
BBB+
Negative
Baa2
Stable
 Commercial Paper
A-2
Negative
Prime-2
Stable
ITCTransmission
 First Mortgage Bonds
A
Negative
A1
Stable
METC
 Senior Secured Notes
A
Negative
A1
Stable
ITC Midwest
 First Mortgage Bonds
A
Negative
A1
Stable
ITC Great Plains
 First Mortgage Bonds
A
Negative
A1
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, 2024, we were not in 
Table of Contents
36

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)
2024
2023
(decrease)
(decrease)
Cash Flows provided by (used in):
Operating activities
$ 
838 $ 
849 $ 
(11) 
 (1) %
Investing activities
 
(1,076)  
(836)  
240 
 29 %
Financing activities
 
(68)  
314  
382 
 122 %
Net (decrease) increase in cash, cash equivalents and 
restricted cash
$ 
(306) $ 
327 
Cash Flows From Operating Activities
Net cash provided by operating activities decreased due to an increase in interest paid of $44 million, an 
increase in property taxes paid of $8 million, a net decrease due to the settlement of interest rate swaps of $7 
million and an increase in income taxes paid of $5 million, and timing differences in various receipts and 
payments during the year ended December 31, 2024 compared to the year ended December 31, 2023. This 
decrease was partially offset by an increase in cash received from operating revenues of $60 million during the 
year ended December 31, 2024 compared to the year ended December 31, 2023.
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, 2024 compared to the year ended December 31, 2023.
Cash Flows From Financing Activities
Net cash used in financing activities increased due to an increase in repayments of long-term debt of 
$275 million, an increase in net repayments under our revolving credit agreements of $167 million, an increase 
in dividend payments of $60 million, an increase in net repayments of refundable deposits from generators for 
transmission network upgrades of $13 million and a decrease in issuances of long-term debt of $5 million, 
during the year ended December 31, 2024 compared to the year ended December 31, 2023. This increase was 
partially offset by a decrease in net repayments of commercial paper of $134 million during the year ended 
December 31, 2024 compared to the year ended December 31, 2023. See Note 9 to the consolidated financial 
statements for additional discussion on debt.
Critical Accounting Estimates
Our 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 
Table of Contents
37

described in Note 7 to the consolidated financial statements, we had regulatory assets and liabilities of $208 
million and $796 million, respectively, as of December 31, 2024. 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 $16 million relating to 
intangible assets at December 31, 2024 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 
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 or IRS regulations;
• 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:
Table of Contents
38

• 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, 2024, the weighted average single equivalent discount rate for the 
benefit obligation was 5.66% and 5.86% 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, 2024, we assumed that our 
pension and postretirement benefit plans’ assets would generate weighted average long-term rates of 
return of 7.30% and 5.50%, respectively.
• Rate of salary increases - As of December 31, 2024, 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, 2024.
• Rate of increase in health care costs - We used a health care cost trend rate of 7.00% for 2025 grading 
down to a 5.00% ultimate rate in 2033 in valuing our postretirement benefit obligation as of December 31, 
2024. These rates are based on a review of recent and expected future experience.
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, 2024:
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 $ 
(12) $ 
15 
Long-term rate of return on plan assets
 
(1)  
1 
N/A
N/A
Change to Postretirement Plan
Discount rate
 
(3)  
3  
(15)  
18 
Long-term rate of return on plan assets
 
(1)  
1 
N/A
N/A
Health care cost trend rate
 
4  
(3)  
16  
(13) 
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 FASB 
guidance.
SEC Rules on Enhancement and Standardization of Climate-Related Disclosures
In March 2024, the SEC adopted rules to enhance and standardize climate-related disclosures. The final 
rules require disclosure of the following information in the footnotes to the financial statements, subject to 
certain materiality thresholds:
• Financial statement effects of severe weather events and other natural conditions;
• Impacts to estimates and assumptions used to produce financial statements associated with severe 
weather events and other natural conditions or any disclosed climate-related targets or transition plans; 
and
• Financial statement effects related to carbon offsets or renewable energy credits/certificates used as part 
of plans to achieve climate-related goals.
Table of Contents
39

In addition, registrants will be required to disclose outside of the financial statements information about: the 
material impact of climate-related risks on its strategy, business model and outlook; risk management processes 
for, and governance and oversight activities of those risks; and material climate-related targets or goals. 
Information related to material greenhouse gas emissions will be required for certain registrants, but will not be 
required for us based on our current filer status.
The final rules include a phased-in compliance period for all registrants, with the compliance date dependent 
on the registrant’s filer status and the content of the disclosure. Based on our current filer status, we will be 
required to comply with the final rules beginning with our annual report for the fiscal year beginning January 1, 
2027. We are assessing the new climate-related disclosure rules, awaiting decisions on their legal status and 
determining an implementation plan to comply with the disclosure requirements in accordance with the 
prescribed timeline.
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 the Revolving 
Credit Agreement, was $6,918 million and $6,660 million at December 31, 2024 and 2023, 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 the Revolving Credit Agreement, was $7,645 million and $7,287 million at 
December 31, 2024 and 2023, respectively. An increase in interest rates of 10% at December 31, 2024 and 
2023 would decrease the fair value of debt by $292 million and $278 million, respectively, at that date, and a 
decrease in interest rates of 10% at December 31, 2024 and 2023 would increase the fair value of debt by $319 
million and $303 million, respectively, at that date.
Revolving Credit Agreement 
At December 31, 2024 and 2023, we had a consolidated total of $247 million and $311 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, 2024 and 2023 would increase 
or decrease annual interest expense by $1 million and $2 million, respectively, at borrowing levels consistent 
with amounts outstanding at the end of each of the respective periods.
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 5-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 2023, we terminated 
$500 million of 10-year U.S. Treasury rate lock contracts that managed interest rate risk associated with the ITC 
Holdings 5.40% Senior Notes, due June 1, 2033. See Note 9 to the consolidated financial statements for 
additional information. At December 31, 2024, we held 5-year interest rate swap contracts with a notional 
amount of $135 million, which manage interest rate risk associated with the forecasted future issuance of fixed-
rate debt at ITC Holdings. At December 31, 2023 ITC Holdings did not have any derivative financial instruments 
outstanding to manage exposure to fluctuations in interest rates.
Table of Contents
40

Credit Risk
Our credit risk is 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 for the year ended December 31, 2024. 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. 
For the year ended December 31, 2023, our credit risk was primarily with DTE Electric, Consumers Energy 
and IP&L, which were responsible for approximately 21.7%, 21.3% and 24.5%, respectively, or $338 million, 
$332 million and $382 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 2021 revenue accruals and 
deferrals and exclude any amounts for the 2023 revenue accruals and deferrals that were included in our 2023 
operating revenues but will not be billed to our customers until 2025.
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.
Table of Contents
41

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
43
Report of Independent Registered Public Accounting Firm (PCAOB ID No. 34)
44
Consolidated Statements of Financial Position as of December 31, 2024 and 2023
46
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2024, 2023 
and 2022
47
Consolidated Statements of Changes in Stockholder’s Equity for the Years Ended December 31, 
2024, 2023 and 2022
48
Consolidated Statements of Cash Flows for the Years Ended December 31, 2024, 2023 and 2022
49
Notes to Consolidated Financial Statements
50
Schedule I — Condensed Financial Information of Registrant
124
Table of Contents
42

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, 2024.
Table of Contents
43

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, 2024 and 2023, the related consolidated statements of 
comprehensive income, stockholder’s equity, and cash flows for each of the three years in the period ended 
December 31, 2024, 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, 2024 and 2023, and the results of its operations and 
its cash flows for each of the three years in the period ended December 31, 2024, 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-
Table of Contents
44

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 13, 2025
We have served as the Company’s auditor since 2001.
Table of Contents
45

ITC HOLDINGS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
December 31,
(In millions of USD, except share data)
2024
2023
ASSETS
Current assets
Cash and cash equivalents
$ 
19 
$ 
328 
Accounts receivable
 
160 
 
137 
Inventory
 
78 
 
63 
Regulatory assets
 
21 
 
30 
Prepaid and other current assets
 
23 
 
21 
Total current assets
 
301 
 
579 
Property, plant and equipment (net of accumulated depreciation and amortization of $2,715 and 
$2,579, respectively)
 
12,129 
 
11,274 
Other assets
Goodwill
 
950 
 
950 
Regulatory assets
 
187 
 
175 
Other assets
 
154 
 
146 
Total other assets
 
1,291 
 
1,271 
TOTAL ASSETS
$ 
13,721 
$ 
13,124 
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities
Accounts payable
$ 
142 
$ 
117 
Accrued compensation
 
57 
 
59 
Accrued interest
 
77 
 
81 
Accrued taxes
 
77 
 
75 
Regulatory liabilities
 
67 
 
41 
Refundable deposits and advances for construction
 
44 
 
31 
Debt maturing within one year
 
— 
 
475 
Other current liabilities
 
20 
 
18 
Total current liabilities
 
484 
 
897 
Accrued pension and postretirement liabilities
 
39 
 
42 
Deferred income taxes
 
1,521 
 
1,411 
Regulatory liabilities
 
729 
 
721 
Refundable deposits
 
11 
 
33 
Long-term debt
 
7,892 
 
7,123 
Other liabilities
 
51 
 
43 
Commitments and contingent liabilities (Notes 6 and 17)
TOTAL LIABILITIES
 
10,727 
 
10,270 
STOCKHOLDER’S EQUITY
Common stock, without par value, 235,000,000 shares authorized, 224,203,112 shares issued and 
outstanding at December 31, 2024 and 2023
 
892 
 
892 
Retained earnings
 
2,074 
 
1,933 
Accumulated other comprehensive income
 
28 
 
29 
Total stockholder’s equity
 
2,994 
 
2,854 
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY
$ 
13,721 
$ 
13,124 
See notes to consolidated financial statements.
Table of Contents
46

ITC HOLDINGS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Year Ended December 31,
(In millions of USD)
2024
2023
2022
OPERATING REVENUES
Transmission and other services
$ 
1,613 
$ 
1,562 
$ 
1,476 
Formula Rate true-up
 
12 
 
(17)  
(10) 
Total operating revenues
 
1,625 
 
1,545 
 
1,466 
OPERATING EXPENSES
Operation and maintenance
 
111 
 
109 
 
107 
General and administrative
 
121 
 
111 
 
105 
Depreciation and amortization
 
326 
 
307 
 
295 
Taxes other than income taxes
 
154 
 
145 
 
139 
Other operating expenses (income), net
 
(1)  
(1)  
(1) 
Total operating expenses
 
711 
 
671 
 
645 
OPERATING INCOME
 
914 
 
874 
 
821 
OTHER EXPENSES (INCOME)
Interest expense, net
 
348 
 
315 
 
269 
Allowance for equity funds used during construction
 
(44)  
(43)  
(37) 
Other expenses (income), net
 
(22)  
(17)  
1 
Total other expenses (income)
 
282 
 
255 
 
233 
INCOME BEFORE INCOME TAXES
 
632 
 
619 
 
588 
INCOME TAX PROVISION
 
148 
 
156 
 
146 
NET INCOME
 
484 
 
463 
 
442 
OTHER COMPREHENSIVE (LOSS) INCOME
Derivative instruments, net of tax
 
(1)  
2 
 
29 
TOTAL OTHER COMPREHENSIVE (LOSS) INCOME, NET OF TAX 
 
(1)  
2 
 
29 
TOTAL COMPREHENSIVE INCOME
$ 
483 
$ 
465 
$ 
471 
See notes to consolidated financial statements.
Table of Contents
47

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
(Loss) Income
Equity
BALANCE, DECEMBER 31, 2021
$ 
892 
$ 
1,584 
$ 
(2) $ 
2,474 
Net income
 
— 
 
442 
 
— 
 
442 
Dividends to ITC Investment Holdings
 
— 
 
(273)  
— 
 
(273) 
Other comprehensive income, net of tax
 
— 
 
— 
 
29 
 
29 
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 
See notes to consolidated financial statements.
Table of Contents
48

ITC HOLDINGS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
(In millions of USD)
2024
2023
2022
CASH FLOWS FROM OPERATING ACTIVITIES
Net income
$ 
484 
$ 
463 
$ 
442 
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense
 
326 
 
307 
 
295 
Recognition, refund and collection of revenue accruals and deferrals — including accrued 
interest
 
(20)  
8 
 
18 
Deferred income tax expense
 
93 
 
105 
 
131 
Allowance for equity funds used during construction
 
(44)  
(43)  
(37) 
Share-based compensation
 
15 
 
15 
 
11 
Other
 
(15)  
10 
 
57 
Changes in assets and liabilities, exclusive of changes shown separately:
Accounts receivable
 
(13)  
2 
 
(8) 
Accounts payable
 
8 
 
(4)  
10 
Accrued interest
 
(3)  
12 
 
12 
Accrued compensation
 
(7)  
(9)  
(15) 
Accrued taxes
 
3 
 
3 
 
7 
Other current and non-current assets and liabilities, net
 
11 
 
(20)  
(31) 
Net cash provided by operating activities
 
838 
 
849 
 
892 
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment
 
(1,062)  
(818)  
(933) 
Other
 
(14)  
(18)  
8 
Net cash used in investing activities
 
(1,076)  
(836)  
(925) 
CASH FLOWS FROM FINANCING ACTIVITIES
Issuances of long-term debt, net
 
884 
 
889 
 
975 
Borrowings under revolving credit agreements
 
1,134 
 
1,196 
 
1,119 
Net repayments of commercial paper
 
— 
 
(134)  
(21) 
Repayments of long-term debt
 
(525)  
(250)  
(500) 
Repayments of revolving credit agreements
 
(1,198)  
(1,093)  
(1,240) 
Dividends to ITC Investment Holdings
 
(343)  
(283)  
(273) 
Refundable deposits from generators for transmission network upgrades
 
9 
 
34 
 
1 
Repayments of refundable deposits from generators for transmission network upgrades
 
(23)  
(35)  
(19) 
Other
 
(6)  
(10)  
(10) 
Net cash (used in) provided by financing activities
 
(68)  
314 
 
32 
NET (DECREASE) INCREASE IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH
 
(306)  
327 
 
(1) 
CASH, CASH EQUIVALENTS AND RESTRICTED CASH — Beginning of period
 
333 
 
6 
 
7 
CASH, CASH EQUIVALENTS AND RESTRICTED CASH — End of period
$ 
27 
$ 
333 
$ 
6 
See notes to consolidated financial statements.
Table of Contents
49

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
Improvements to Reportable Segment Disclosures
In November 2023, the FASB issued authoritative guidance to improve reportable segment disclosure 
requirements, thereby enabling investors to better understand an entity’s performance and assess potential 
future cash flows. The new guidance requires that public entities disclose, on an annual and interim basis, 
additional information related to significant segment expenses regularly provided to the CODM and other 
segment items. The guidance also contains several other provisions, notably requiring disclosure in interim 
periods of all annual disclosures about a reportable segment’s profit or loss and assets currently required by 
Topic 280 of the FASB’s Accounting Standards Codification. We have adopted the required disclosure 
modifications in fiscal year reporting for the period ended December 31, 2024 and will adopt required 
modifications for interim period reporting beginning in 2025. See Note 19 for disclosures of segment information 
incorporating these requirements.
Recently Issued 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 in the new guidance include disaggregation of income tax information by jurisdiction and 
changes to the presentation of information for the reconciliation of effective tax rates. The guidance is effective 
for fiscal years beginning after December 15, 2024 with early adoption permitted. We are evaluating the new 
guidance, but do not anticipate significant changes to our disclosures.
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 
Table of Contents
50

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, with early adoption permitted. We are evaluating the impact of the new guidance on 
our 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, 2024, 2023 and 2022. 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. 
Table of Contents
51

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 
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 expense. 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, 2024 and 2023, we had goodwill 
Table of Contents
52

balances recorded at ITCTransmission, METC and ITC Midwest of $173 million, $454 million and $323 
million, respectively.
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, 2024 and 
determined that no impairment exists. There were no events subsequent to October 1, 2024 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 agreements, 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 and $5 million as of December 31, 2024 and 2023, respectively, 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 that are designated in 
hedging relationships are generally 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 
additional discussion 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 
Table of Contents
53

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.
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.
Table of Contents
54

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, 2024, we have not recognized any uncertain income tax positions.
We file our federal and Michigan income tax returns as part of the FortisUS consolidated 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. Our prior consolidated federal tax returns are no longer subject to U.S. federal tax 
examinations for tax years 2020 and earlier. State and city jurisdictions that remain subject to examination 
range from tax years 2020 to 2023. 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 Note 10 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 the 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 information on changes in 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 ancillary services relating to customer-owned plant, easement and rental 
revenues. 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 the year ended December 31, 2024 and $6 million for each of the years ended December 31, 
2023 and 2022.
Table of Contents
55

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)
2024
2023
Trade accounts receivable
$ 
2 $ 
2 
Unbilled accounts receivable
 
135  
122 
Other
 
23  
13 
Total accounts receivable
$ 
160 $ 
137 
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.
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, 2024:
(In millions of USD)
Total
Net regulatory liabilities as of December 31, 2023
$ 
(28) 
Net refund of 2022 revenue deferrals and accruals, including accrued interest
 
11 
Net revenue accruals, including accrued interest
 
11 
Net accrued interest payable
 
(2) 
Net regulatory liabilities as of December 31, 2024
$ 
(8) 
Table of Contents
56

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, 2024, 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.
Table of Contents
57

7. REGULATORY ASSETS AND LIABILITIES
The following table summarizes the regulatory asset and liability balances:
December 31,
(In millions of USD)
2024
2023
Regulatory assets:
Current:
Revenue accruals (including accrued interest of $2 and $2, respectively) 
(a)
$ 
21 $ 
30 
Total current
 
21  
30 
Non-current:
Revenue accruals (including accrued interest of $1 and $1, respectively) 
(a)
 
26  
20 
Income taxes recoverable related to AFUDC equity
 
141  
130 
Pensions and postretirement
 
8  
9 
Other
 
12  
16 
Total non-current
 
187  
175 
Total regulatory assets
$ 
208 $ 
205 
Regulatory liabilities:
Current:
Revenue deferrals (including accrued interest of $4 and $3, respectively) 
(a)
$ 
40 $ 
41 
Refund related to the October 2024 Order (including accrued interest of $6 
and $—, respectively) (b)
 
27  
— 
Total current
 
67  
41 
Non-current:
Revenue deferrals (including accrued interest of $1 and $1, respectively) 
(a)
 
15  
37 
Pensions and postretirement
 
68  
62 
Accrued asset removal costs
 
141  
111 
Refundable excess deferred state income taxes
 
52  
46 
Refundable excess deferred federal income taxes
 
453  
465 
Total non-current
 
729  
721 
Total regulatory liabilities
$ 
796 $ 
762 
____________________________
(a) Refer to discussion of revenue accruals and deferrals in Note 6 under “Cost-Based Formula Rates with 
True-Up Mechanism.” Our Regulated Operating Subsidiaries 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.
(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.
Table of Contents
58

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 
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 a reduction in corporate income tax rates in certain states we operate in, we revalued 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 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, 2024 and 2023, 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, 2024 and 2023, 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)
2024
2023
Property, plant and equipment
Regulated Operating Subsidiaries:
Property, plant and equipment
$ 
13,913 $ 
12,902 
Construction work in progress
 
670  
712 
Capital equipment
 
160  
134 
Other
 
87  
91 
ITC Holdings and other
 
14  
14 
Total
 
14,844  
13,853 
Less: Accumulated depreciation and amortization
 
(2,715)  
(2,579) 
Property, plant and equipment, net
$ 
12,129 $ 
11,274 
Additions to property, plant and equipment and construction work in progress during 2024 and 2023 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 $320 million, $300 million and 
$286 million for the years ended December 31, 2024, 2023 and 2022, respectively.
Table of Contents
59

Certain of 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 a return on equity capital devoted to construction of assets. The interest 
component of AFUDC was a reduction to interest expense of $12 million, $11 million and $9 million for the years 
ended December 31, 2024, 2023 and 2022, respectively.
Table of Contents
60

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)
2024
2023
ITC Holdings 6.375% Senior Notes, due September 30, 2036
$ 
200 
$ 
200 
ITC Holdings 3.65% Senior Notes, due June 15, 2024 (a)
 
— 
 
400 
ITC Holdings 5.30% Senior Notes, due July 1, 2043
 
300 
 
300 
ITC Holdings 3.25% Notes, due June 30, 2026
 
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 
 
— 
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 
 
— 
ITCTransmission 5.38% First Mortgage Bonds, Series L, due January 23, 2034
 
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 
 
— 
ITC Midwest 6.15% First Mortgage Bonds, Series A, due January 31, 2038
 
175 
 
175 
ITC Midwest 4.60% First Mortgage Bonds, Series D, due December 17, 2024 (a)
 
— 
 
75 
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 
 
— 
ITC Midwest 5.25% First Mortgage Bonds, Series N, due December 10, 2043
 
125 
 
— 
ITC Great Plains 4.16% First Mortgage Bonds, Series A, due November 26, 2044
 
100 
 
150 
Revolving Credit Agreement, due April 14, 2028
 
247 
 
311 
Other
 
2 
 
3 
Total principal
 
7,939 
 
7,644 
Unamortized deferred financing fees and discount (b)
 
(47)  
(46) 
Total debt
$ 
7,892 
$ 
7,598 
____________________________
(a) As of December 31, 2024 there was no debt maturing within one year on the consolidated statements of 
financial position. At December 31, 2023 there was $475 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.
Table of Contents
61

(b) We recorded $7 million for the year ended December 31, 2024 and $6 million for each of the years ended 
December 31, 2023 and 2022 to interest expense for the amortization of deferred financing fees and debt 
discounts.
The annual maturities of debt as of December 31, 2024 are as follows:
(In millions of USD)
2025
$ 
— 
2026
 
400 
2027
 
1,575 
2028
 
338 
2029
 
75 
2030 and thereafter
 
5,551 
Total
$ 
7,939 
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.
On June 1, 2023, ITC Holdings completed a private offering of Senior Notes totaling $800 million, which 
included $500 million aggregate principal amount of unsecured 5.40% Senior Notes, due June 1, 2033, and an 
additional $300 million aggregate principal amount issued of its existing unsecured 4.95% Senior Notes, due 
September 22, 2027. The issuance increased the total aggregate principal amount issued of the 4.95% Senior 
Notes to $900 million. The 5.40% and the 4.95% Senior Notes are redeemable prior to March 1, 2033 and 
August 22, 2027, respectively, in whole or in part and at the option of ITC Holdings, by paying an applicable 
make whole premium. A portion of the total net proceeds from the offering, after discount and costs related to 
the issuances, was used to redeem in full $250 million aggregate principal amount of ITC Holdings 4.05% 
Senior Notes, due July 1, 2023, to repay indebtedness outstanding under the commercial paper program and 
for general corporate purposes. The 4.95% and 5.40% 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 Sixth 
and Seventh Supplemental Indentures, dated as of September 22, 2022 and June 1, 2023, respectively.
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, 
2024 and 2023, 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.
Table of Contents
62

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 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. 
Table of Contents
63

Revolving Credit Agreement
At December 31, 2024, 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  
62  
113 
 5.38 %
 0.100 %
METC
 
175  
72  
103 
 5.38 %
 0.100 %
ITC Midwest
 
225  
46  
179 
 5.38 %
 0.100 %
ITC Great Plains
 
75  
67  
8 
 5.38 %
 0.100 %
Total
$ 
1,000 $ 
247 $ 
753 
____________________________
(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. In June 
2024, we adjusted our current borrowing sublimits, which resulted in an increase to ITC Great Plains of 
$50 million and a decrease to ITC Holdings of $50 million.
(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.
Derivative Instruments and Hedging Activities
We use derivative financial instruments to manage our exposure to fluctuations in interest rates. During 2023 
and 2024, ITC Holdings entered into the following derivative instruments that 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
$ 
135 
 3.27 % $ 
— 
5
Q2 2026
Settled derivative instruments
U.S. Treasury rate lock contracts (b)
 
300 
 4.66 %  
(3) 
5
Q2 2024
U.S. Treasury rate lock contracts (b)
 
500 
 3.46 %  
4 
10
Q2 2023
____________________________
(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. 
(b) The settlement payment was recognized within cash flows from operating activities in the consolidated 
statements of cash flows.
In 2025, ITC Holdings entered into interest rate swaps with notional amounts totaling $95 million, increasing 
the notional amount of outstanding interest rate swaps to $230 million and the weighted average fixed rate to 
3.56%. The contracts manage interest rate risk associated with the forecasted future issuance of fixed-rate debt 
at ITC Holdings. The interest rate swaps are expected to qualify for cash flow hedge accounting treatment.
Table of Contents
64

10. INCOME TAXES
For the years ended December 31, 2024, 2023 and 2022, our effective tax rates were 23.4%, 25.2% and 
24.8%, 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)
2024
2023
2022
Income tax expense at 21% federal statutory rate
$ 
133 $ 
130 $ 
123 
State income taxes (net of federal benefit) (a)
 
30  
43  
36 
AFUDC equity
 
(7)  
(7)  
(6) 
Amortization of revalued deferred federal income taxes
 
(9)  
(9)  
(9) 
Valuation allowance
 
1  
(2)  
1 
Other, net
 
—  
1  
1 
Total income tax provision
$ 
148 $ 
156 $ 
146 
____________________________
(a) Amounts for the years ended December 31, 2023 and 2022 include the impact of the remeasurement of 
certain deferred tax balances and NOLs for Iowa due to the corporate tax rate change discussed herein.
Components of the income tax provision were as follows:
Year Ended December 31,
(In millions of USD)
2024
2023
2022
Current income tax expense 
$ 
55 $ 
51 $ 
15 
Deferred income tax expense
 
93  
105  
131 
Total income tax provision
$ 
148 $ 
156 $ 
146 
Deferred income tax assets (liabilities) consisted of the following:
December 31,
(In millions of USD)
2024
2023
Property, plant and equipment
$ 
(1,573) $ 
(1,461) 
Goodwill
 
(147)  
(148) 
Regulatory liability gross up due to change in federal income tax rate
 
115  
119 
Pension and postretirement liabilities
 
21  
22 
State income tax NOLs (net of federal benefit) 
 
41  
39 
Valuation allowance
 
(4)  
(3) 
Other, net
 
26  
21 
Net deferred income tax liabilities 
$ 
(1,521) $ 
(1,411) 
Gross deferred income tax liabilities
$ 
(1,752) $ 
(1,642) 
Gross deferred income tax assets
 
235  
234 
Valuation allowance
 
(4)  
(3) 
Net deferred income tax liabilities
$ 
(1,521) $ 
(1,411) 
We had state income tax NOLs as of December 31, 2024, which expire in the years 2025 to 2043 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.
Iowa Corporate Tax Rate
On March 1, 2022, the governor of Iowa signed an act into law that contains provisions to reduce Iowa’s 
corporate tax rates if a certain threshold of the state’s annual net corporate income tax receipts is met. 
Table of Contents
65

Adjustments to reduce the corporate income tax rate are calculated annually after the end of each fiscal year 
and may continue until the currently targeted corporate income tax rate of 5.5% is reached.
In September 2022, a reduction in Iowa’s top corporate income tax rate from 9.8% to 8.4% was certified, 
effective January 1, 2023, and in September 2023, an additional reduction from 8.4% to 7.1% was certified, 
effective January 1, 2024. Following the reduction, we revalued certain deferred tax balances and net operating 
losses impacted by the change in the Iowa corporate income tax rate. As a result, deferred income tax expense 
of $6 million and $7 million was recorded during the years ended December 31, 2023 and 2022, respectively. In 
addition, an increase to the regulatory liability of $21 million and $22 million was recorded as of December 31, 
2023 and 2022, respectively, to offset deferred taxes associated with rate base at ITC Midwest. There was no 
change in the Iowa state income tax rate in 2024. See Note 7 for additional information on the regulatory liability 
related to reductions in corporate income tax rates.
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 and $3 million in 2024 and 2022, respectively. We did not contribute to the retirement plan in 2023. 
We expect to contribute $3 million to the retirement plan in 2025.
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 
“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 and 
$48 million at December 31, 2024 and 2023, respectively, 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 $1 million to the supplemental benefits plan in each of 2024 and 2023. We did not contribute to 
the supplemental benefit plans in 2022.
We provide certain postretirement health care, dental and life insurance benefits for eligible employees (the 
“postretirement benefit plan”). We contributed $1 million and $7 million to the postretirement benefit plan in 2023 
and 2022, respectively. We did not contribute to the postretirement benefit plan in 2024. We do not expect to 
contribute to the postretirement benefit plan in 2025.
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)
2024
2023
2022
2024
2023
2022
Service cost
$ 
8 $ 
7 $ 
8 $ 
7 $ 
7 $ 
12 
Interest cost
 
7  
6  
4  
5  
5  
4 
Expected return on plan assets
 
(8)  
(6)  
(7)  
(8)  
(6)  
(7) 
Amortization of prior service credit  
—  
—  
—  
—  
(1)  
— 
Amortization of unrecognized 
loss/(gain)
 
—  
—  
1  
(5)  
(4)  
(2) 
Net periodic benefit cost/(credit)
$ 
7 $ 
7 $ 
6 $ 
(1) $ 
1 $ 
7 
Table of Contents
66

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)
2024
2023
2024
2023
Change in Benefit Obligation:
Beginning projected benefit obligation / 
accumulated postretirement benefit obligation
$ 
(140) $ 
(124) $ 
(97) $ 
(90) 
Service cost
 
(8)  
(7)  
(7)  
(7) 
Interest cost
 
(7)  
(6)  
(5)  
(5) 
Actuarial net gain/(loss)
 
6  
(11)  
(3)  
3 
Benefits paid
 
8  
8  
3  
2 
Settlements
 
2  
—  
—  
— 
Plan participants’ contributions
 
—  
—  
(1)  
— 
Ending projected benefit obligation / accumulated 
postretirement benefit obligation
 
(139)  
(140)  
(110)  
(97) 
Change in Plan Assets:
Beginning plan assets at fair value
 
105  
96  
141  
122 
Actual return on plan assets
 
9  
13  
16  
20 
Employer contributions
 
4  
—  
—  
1 
Benefits paid
 
(4)  
(4)  
(3)  
(2) 
Plan participants’ contributions
 
—  
—  
1  
— 
Ending plan assets at fair value
 
114  
105  
155  
141 
Funded status, (underfunded)/overfunded
$ 
(25) $ 
(35) $ 
45 $ 
44 
Accumulated benefit obligation:
Retirement plan
$ 
(92) $ 
(89) 
N/A
N/A
Supplemental benefit plans
 
(42)  
(45) 
N/A
N/A
Total accumulated benefit obligation 
$ 
(134) $ 
(134) 
N/A
N/A
Amounts recorded as:
Funded Status:
Accrued pension and postretirement liabilities
$ 
(39) $ 
(42) $ 
— $ 
— 
Other non-current assets
 
19  
12  
45  
44 
Other current liabilities
 
(5)  
(5)  
—  
— 
Total
$ 
(25) $ 
(35) $ 
45 $ 
44 
Unrecognized Amounts in Non-Current 
Regulatory Assets:
Net actuarial loss
$ 
8 $ 
9 $ 
— $ 
— 
Total
$ 
8 $ 
9 $ 
— $ 
— 
Unrecognized Amounts in Non-Current 
Regulatory Liabilities:
Net actuarial (gain)
$ 
(8) $ 
(1) $ 
(61) $ 
(61) 
Net prior service cost/(credit)
 
1  
1  
—  
(1) 
Total
$ 
(7) $ 
— $ 
(61) $ 
(62) 
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 
Table of Contents
67

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, 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, 2023 within the change in benefit obligation for the pension plans is primarily the result of 
decreases in the discount rates and increases in the rate of salary increases and the interest crediting rate. The 
net actuarial loss for the year ended December 31, 2024 within the change in benefit obligation for the 
postretirement benefit plan is due to impacts of $8 million for demographic assumption changes and experience 
and $5 million due to financial assumptions changes, primarily an updated healthcare cost trend rate, partially 
offset by an impact of $10 million from the increase 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)
2024
2023
Projected benefit obligation
$ 
(44) $ 
(47) 
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)
2024
2023
Accumulated benefit obligation
$ 
(42) $ 
(45) 
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.
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,
2024
2023
2022
2024
2023
2022
Weighted average discount rate
5.66%
5.19%
5.52%
5.86%
5.30%
5.65%
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
Annual rate of increase in dental benefit costs
N/A
N/A
N/A
4.50%
4.50%
4.50%
Table of Contents
68

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,
2024
2023
2022
2024
2023
2022
Weighted average discount rate — service 
cost
5.26%
5.59%
3.05%
5.48%
5.83%
3.32%
Weighted average discount rate — interest 
cost
5.10%
5.40%
2.44%
5.17%
5.51%
2.87%
Weighted average interest crediting rate
4.50%
4.00%
4.00%
N/A
N/A
N/A
Annual rate of salary increases
4.50%
4.00%
4.00%
4.50%
4.00%
4.00%
Health care cost trend rate
N/A
N/A
N/A
6.50%
6.75%
5.75%
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
2030
2030
2025
Expected long-term rate of return on plan 
assets
7.30%
6.90%
5.90%
5.50%
5.20%
4.50%
At December 31, 2024, 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
2025
$ 
11 $ 
3 
2026
 
10  
3 
2027
 
11  
4 
2028
 
10  
4 
2029
 
12  
5 
2030 through 2034
 
72  
33 
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, 2024 and 2023, 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
2024
2024
2023
2024
2023
Fixed income securities
 50 %
 51 %
 50 %
 50 %
 50 %
Equity securities
 50 %
 49 %
 50 %
 50 %
 50 %
Total
 100 %
 100 %
 100 %
 100 %
 100 %
Table of Contents
69

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.
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, 2024 and 2023, there were no transfers between levels.
For the years ended December 31, 2024 and 2023, the fair value of retirement plan and postretirement 
benefit plan assets measured on a recurring basis at the Level 1 tier were as follows:
Pension Plans
Postretirement Benefit Plan
December 31,
December 31,
(In millions of USD)
2024
2023
2024
2023
Mutual funds — U.S. equity securities
$ 
45 $ 
42 $ 
74 $ 
68 
Mutual funds — international equity securities
 
11  
11  
3  
3 
Mutual funds — fixed income securities
 
58  
52  
78  
70 
Total
$ 
114 $ 
105 $ 
155 $ 
141 
The mutual funds consist primarily of publicly traded mutual funds and are recorded at fair value based on 
observable trades for identical securities in an active market.
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 $7 million for each of the 
years ended December 31, 2024, 2023 and 2022.
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, 2024 and 2023, there were no transfers between levels.
Table of Contents
70

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 $ 
— 
Our assets measured at fair value subject to the three-tier hierarchy at December 31, 2023, 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:
Mutual funds — fixed income securities
$ 
44 $ 
— $ 
— 
Mutual funds — equity securities
 
14  
—  
— 
Total
$ 
58 $ 
— $ 
— 
As of December 31, 2024 and 2023, we held certain assets that are required to be measured at fair value on 
a recurring basis. The assets consist of investments recorded within cash and cash equivalents and other long-
term assets, including 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.
As of December 31, 2024, the assets 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 
Secured Overnight Financing Rate swap rates, 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, 2024 and 2023. 
Fair Value of Financial Assets and Liabilities
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 our consolidated long-term debt 
and debt maturing within one year, excluding borrowings on the Revolving Credit Agreement, was $6,918 
million and $6,660 million at December 31, 2024 and 2023, respectively. These fair values represent Level 2 
under the three-tier hierarchy described above. 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, was $7,645 million and $7,287 million at December 31, 2024 and 2023, 
respectively.
Table of Contents
71

Revolving Credit Agreement
At December 31, 2024 and 2023, we had a consolidated total of $247 million and $311 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. These fair values represent Level 2 under the three-tier hierarchy described 
above.
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.
13. STOCKHOLDER'S EQUITY
Accumulated Other Comprehensive Income (Loss)
The following table provides the components of changes in AOCI:
Derivative instruments
Reclassification of net (gain) loss relating to interest rate cash flow 
hedges from AOCI to earnings (net of tax of $(1), $— and $1, 
respectively) (a)
 
(2)  
(1)  
3 
Gain on interest rate swaps relating to interest rate cash flow hedges 
(net of tax of $—, $1 and $11, respectively)
 
1  
3  
26 
Total other comprehensive (loss) income, net of tax
 
(1)  
2  
29 
Balance at the end of period
$ 
28 $ 
29 $ 
27 
Year Ended December 31,
(In millions of USD)
2024
2023
2022
Balance at the beginning of period
$ 
29 $ 
27 $ 
(2) 
____________________________
(a) The reclassification of the net (gain) loss 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, 2025 is expected to be approximately $4 million (net of tax of $1 
million). 
14. SHARE-BASED COMPENSATION
We recorded share-based compensation costs as follows:
Year Ended December 31,
(In millions of USD)
2024
2023
2022
Operation and maintenance expenses
$ 
2 $ 
2 $ 
2 
General and administrative expenses
 
13  
13  
9 
Amounts capitalized to property, plant and equipment
 
12  
8  
8 
Total share-based compensation costs
$ 
27 $ 
23 $ 
19 
Total tax benefit recognized in the consolidated statements of 
comprehensive income
$ 
7 $ 
6 $ 
5 
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 
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 
Table of Contents
72

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, 2024:
Number of
Performance
Based Units
PBUs at December 31, 2023
 
851,048 
Granted
 
353,948 
Vested and paid out
 
(286,072) 
Forfeited
 
(19,930) 
PBUs at December 31, 2024
 
898,994 
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)
2024
2023
Accrued compensation
$ 
10 $ 
18 
Other long-term liabilities
 
17  
12 
Total
$ 
27 $ 
30 
The aggregate fair value of PBUs as of December 31, 2024 and 2023 was $37 million and $40 million, 
respectively. At December 31, 2024, $10 million of total unrecognized compensation cost related to PBUs not 
yet vested is expected to be recognized over the remaining weighted average period of 1.7 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, 2024:
Number of
Service
Based Units
SBUs at December 31, 2023
 
658,207 
Granted
 
296,990 
Vested and paid out
 
(223,294) 
Forfeited
 
(19,930) 
SBUs at December 31, 2024
 
711,973 
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)
2024
2023
Accrued compensation
$ 
9 $ 
9 
Other long-term liabilities
 
13  
10 
Total
$ 
22 $ 
19 
The aggregate fair value of SBUs as of December 31, 2024 and 2023 was $31 million and $26 million, 
respectively. At December 31, 2024, $9 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.
Table of Contents
73

15. JOINTLY OWNED UTILITY PLANT/COORDINATED SERVICES
As of December 31, 2024, 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 $ 
5 $ 
— 
Cardinal Hickory Creek (b)
 91.0 %  
303  
6  
— 
Other (c)
ITCTransmission
 49.6 %  
29  
20  
13 
METC
various  
58  
40  
— 
ITC Midwest
various  
96  
20  
2 
ITC Great Plains
 49.0 %  
33  
5  
— 
____________________________
(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 4, 2025, our Board of Directors approved a $72 million dividend to ITC Investment Holdings 
that is expected to be paid on February 27, 2025.
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)
2024
2023
Statements of financial position activity:
Accounts receivable from Fortis and Fortis affiliates
$ 
1 $ 
1 
Net income tax payable to ITC Investment Holdings (a)
 
7  
6 
__________________________
(a) Recorded in accrued taxes on the consolidated statements of financial position.
Year Ended December 31,
(In millions of USD)
2024
2023
2022
Comprehensive income statements activity:
Billed from Fortis and Fortis affiliates (a)
$ 
13 $ 
12 $ 
13 
Billed to Fortis and Fortis affiliates (b)
 
4  
3  
2 
____________________________
(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.
Table of Contents
74

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
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.
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 
Table of Contents
75

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 and during the year ended December 31, 2022, 
we received net settlement payments of less than $1 million owed from customers.
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 
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. As 
of December 31, 2024, we recorded an aggregate refund liability of $27 million, including interest of $6 million, 
in accordance with the refund provisions of the order.
Table of Contents
76

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, 2024, we had purchase obligations of $156 million representing commitments for materials, 
services and equipment that had not been received as of December 31, 2024, primarily for construction and 
maintenance projects for which we have an executed contract. Of these purchase obligations, $136 million is 
expected to be paid in 2025, with the majority of the items related to materials and equipment that have long 
production lead times.
Other Commitments
METC
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 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
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.
Concentration of Credit Risk
Our credit risk is 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 for the year ended December 31, 2024. 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. 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 
Table of Contents
77

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)
2024
2023
2022
Cash and cash equivalents
$ 
19 $ 
328 $ 
4 
Restricted cash included in other non-current assets
 
8  
5  
2 
Total cash, cash equivalents and restricted cash
$ 
27 $ 
333 $ 
6 
Supplementary Cash Flows Information
Year Ended December 31,
(In millions of USD)
2024
2023
2022
Interest paid (net of interest capitalized)
$ 
340 $ 
296 $ 
247 
Income taxes paid (a)
 
54  
49  
11 
Non-cash investing and financing activities:
Additions to property, plant and equipment and other long-lived assets (b)  
153  
130  
117 
Allowance for equity funds used during construction
 
44  
43  
37 
Other
 
—  
1  
1 
____________________________
(a) Includes amounts paid to ITC Investment Holdings under a tax sharing agreement. Payments made directly 
to certain state jurisdictions were $1 million for the year ended December 31, 2024 and less than $1 million 
for each of the years ended December 31, 2023 and 2022.
(b) 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, 2024, 
2023 or 2022, respectively, but will be or have been included as a cash outflow from investing activities for 
expenditures for property, plant and equipment or repayments of contributions in aid of construction 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 
Table of Contents
78

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.
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 
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 
Table of Contents
79

Regulated
Operating
ITC Holdings
Reconciliations/
2022
Subsidiaries
and Other
Eliminations
Total
(In millions of USD)
Operating revenues
$ 
1,503 $ 
1 $ 
(38) $ 
1,466 
Depreciation and amortization
 
295  
—  
—  
295 
Interest expense, net
 
134  
135  
—  
269 
Other segment items (a)
 
338  
14  
(38)  
314 
Income (loss) before income taxes
 
736  
(148)  
—  
588 
Income tax provision (benefit) 
 
179  
(33)  
—  
146 
Subsidiary net earnings
 
—  
557  
(557)  
— 
Net income 
 
557  
442  
(557)  
442 
Property, plant and equipment, net
 
10,630  
7  
—  
10,637 
Goodwill
 
950  
—  
—  
950 
Total assets (b)
 
12,005  
6,378  
(6,252)  
12,131 
Capital expenditures
 
933  
—  
—  
933 
____________________________
(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.
Table of Contents
80

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, 2024 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.
Table of Contents
81

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, 55. 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 
currently serves as a director of the Fortis utility subsidiary, FortisAlberta Inc. The Board selected Ms. Apsey to 
serve as a director due to her position as Chief Executive Officer of the Company.
Leanne M. Bell, 64. 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 Nadara Energy Services Limited and Third Coast Midstream, LLC. 
She previously served on the board of Nassau Financial Group from July 2016 to July 2024, Onward Energy 
Services from 2018 to 2020 and John Laing Group from 2020 to 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.
Geoffrey Chatas, 62. Mr. Chatas became a director of the Company in November 2024. Mr. Chatas is 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 since October 2021. Mr. Chatas was the Senior Vice President 
and Chief Operating Officer for Georgetown University from February 2018 to September 2021. Prior to that, he 
was the Vice President for Business and Finance and Chief Financial Officer at The Ohio State University. In 
2015, 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.
Robert A. Elliott, 69. 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. He also serves as an Investment Advisor Representative for 
Greenberg Financial Group, a brokerage firm, a position in which he has served since 2001. 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 
Table of Contents
82

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, 59. 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 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, 69. 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, 58. 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 
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 25 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 FortisBC and previously served on the UNS Energy Corporation board from 2013 to 2020 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, 68. 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 of the 
Compensation Committee, CTC Global Corp., and Stone Mountain Technologies, Inc. He is also an Operating 
Partner with Energy Impact Partners, LP, 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.
Table of Contents
83

Jocelyn H. Perry, 54. 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, 66. 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, 69. 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.
A. Douglas Rothwell, 68. 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 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 Walker, 63. 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.
Table of Contents
84

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, 55. Ms. Apsey’s background is described above under “Directors.”
Gretchen L. Holloway, 50. 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, is the Chair of the Finance & Audit Committee for the Children’s Foundation, and is a member of 
Women Thrive Advisory Board.
Brian Slocum, 48. 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 Ascension 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, 52. 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 
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 K. Tanner, 50. 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 
Table of Contents
85

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 for the American Clean Power Association.
Simon Whitelocke, 52. 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 
officers who were serving as such at December 31, 2024. We refer to these individuals collectively as the 
“named executive officers” (or “NEOs”).
The Company’s named executive officers for 2024 were:
Name
Position
Linda H. Apsey
Chief Executive Officer, Former President
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, Former Senior Vice President and Chief Business Officer
In July 2024, the role of President transitioned from Ms. Apsey to Ms. Tanner, who had been serving as our 
Senior Vice President and Chief Business Officer since February 2019. Ms. Apsey remains our Chief Executive 
Officer.
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 
Table of Contents
86

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 2024:
• Base salary increases. Base salary increases were provided to each of our NEOs in 2024 to reward 
individual performance and to remain competitive and aligned with market.
• Annual cash incentive bonuses. The NEOs earned cash incentive bonuses for 2024 performance of 
approximately 180% of target. This was based on achieving 100% of the performance targets established 
under the ACPB in early 2024 and achievement of certain performance factors which resulted in a bonus 
multiplier of 1.8x. 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 2024. 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 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;
• 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 the impact of the program 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 2024, FW Cook reviewed the attributes and 
structure of our executive compensation programs for the purpose of identifying potential sources of risk within 
the program design. The review covered compensation plan design and administration/governance risk.
Table of Contents
87

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 2023, 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 25th percentile to 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 
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 2024 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 
Table of Contents
88

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 2024 annualized base salaries for the NEOs, including any year-over-year change, were:
NEO
2023 Base 
Salary
2024 Base 
Salary
Percent Increase
Linda H. Apsey
$ 
900,000 
$ 
936,000 
 4.0% 
Gretchen L. Holloway
 
434,700 
 
447,700 
 3.0 %
Brian Slocum
 
426,000 
 
468,600 
 10.0 %
Christine Mason Soneral
 
418,000 
 
430,500 
 3.0 %
Krista Tanner
 
389,400 
 
535,000 
 37.4 %
The increase for Mr. Slocum and initial increase for Ms. Tanner (from an annualized amount of $389,400 in 
2023 to an annualized amount of $436,100 at the beginning of 2024) considered the market median data and 
each executive’s sustained performance. Ms. Tanner’s base salary was further increased to an annualized 
amount of $535,000 in connection with her appointment to President in July 2024.
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 
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 2024, the ACPB consisted of four primary measurement categories: Financial, Safety & Compliance, 
Culture 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.
Table of Contents
89

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 2024, 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
2024 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 2024 
Board-approved budget.
Non-Field O&M and G&A 
expense at or under budget 
of $170M.
 10% 
$164M
 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 2024 
Board-approved budget.
Adjusted Net Income at or 
above $625M to achieve 
10%; 
Adjusted Net Income at or 
above $594M to achieve 
5%.
5 - 10%
 
$632M 
 10% 
Total
 20% 
 20% 
Table of Contents
90

Safety & Compliance goals represented 15% 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
2024 Results
Actual 
Payout
Safety & 
Compliance
15% 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.
Perform High-Energy 
Control Assessment 
(HECA) on 7 high-energy 
hazard types; evaluate for 
direct controls and develop 
plans for any gaps found.
 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 reduced by 1 from prior 
year and 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.
 5% 
5 / 1
 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 2024 
Cyber Security Plan, as 
presented to and approved 
by the Board of Directors.
 5% 
Completed
 5% 
Total
 15% 
 15% 
The Culture goal represents 5% of the total maximum annual bonus target and includes the implementation 
of specific inclusion and diversity goals.
Category
Goal
Rationale for 
Goal
Rationale for Target Goal
Potential 
Payout
2024 Results
Actual 
Payout
Culture
5% Maximum 
Potential Payout
Inclusion and 
Diversity
Supporting an 
inclusive and 
diverse culture 
creates an 
environment that 
respects the 
contributions and 
differences of 
every individual 
and drives 
business success.
Goal focused on education 
and awareness activities.
Active employees complete 
a minimum of two (2) 
inclusion and diversity 
education and awareness 
activities. Dependent on 
individual achievement.
 5 %
Completed
 5 %
Total
 5 %
 5 %
Table of Contents
91

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
2024 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 (13 or 
fewer, representing top 
decile performance); 
METC (23 or fewer, 
representing top decile 
performance);
ITC Midwest (58 or fewer, 
representing top decile 
performance, no more than 
47 at the 69kV level 
representing top quartile 
performance.); 
Each target is worth 5%.
 15% 
ITCTransmissi
on - 7
METC - 22
ITC Midwest - 
41 / 29
 15% 
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 2024 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 $96M.
 15% 
All high 
priority Field 
O&M 
initiatives 
completed 
under budget 
at $92M
 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 
2024, with a threshold level 
also established.
Complete $963M of the 
2024 Capital Project Plan to 
achieve 30%; Complete 
$912M to achieve 15%.
15 - 30%
$1,133M
 30% 
Total
 60% 
 60% 
Total Bonus (as a percent of target bonus level)
 100% 
 100% 
Table of Contents
92

____________________________
(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 as 
follows:
(In millions of USD)
2024
Net income of Regulated Operating Subsidiaries
$ 
612 
Adjustments related to ROE matters
 
20 
Adjusted net income
$ 
632 
Additionally, our executives, including the NEOs, are eligible for an executive bonus multiplier. To further 
motivate management to provide value to the shareholder, in 2024 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 Project Plan
$963M
$1,115M
$1,133M
2.00x
50%
1.00x
Adjusted Consolidated 
Net Income (1)
$482M
$504M
$504M
2.00x
20%
0.40x
Strategic Objective
Achieve 
Objective
Achieve 
Objective
Not Achieved
1.00x
20%
0.20x
Inclusion & Diversity 
Plan
Achieve 1 
Goal
Achieve 2 
Goals
Achieved 2 of 2
2.00x
10%
0.20x
Bonus Multiplier
1.80x
____________________________
(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)
2024
Net income
$ 
484 
Adjustments related to ROE matters
 
20 
Adjusted consolidated net income
$ 
504 
Each measure has an established scale, which includes a threshold level and below equating to a 1.00x 
multiplier, having no impact on the bonus award, to a maximum of 2.00x, which would increase the bonus by 
100% to a maximum of 200% of target. Achievement against performance scales related to each of the above 
metrics produced an executive bonus multiplier of 1.8x. This performance factor was applied to the ACPB factor 
of 100% to produce a final payment of approximately 180% 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 2024 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 2024 to the NEOs were made pursuant to terms stated in the SBU and PBU award agreements.
Table of Contents
93

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 January 
2024, 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 
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 2024. 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, Total Shareholder Return (relative to 
Fortis’ peer group) weighted at 45%, ITC cumulative consolidated net income weighted at 45% and Fortis 
Carbon Reduction Performance weighted at 10%. These PBU metrics were selected because Total Shareholder 
Return aligns with the Fortis shareholder experience, cumulative consolidated net income measures our 
sustained growth (organic and development), cost management and efficiency and carbon reduction 
performance supports a corporate-wide goal of 75% reduction in Scope 1 emissions by 2035. 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 2024 awards were made, the award values were targeted to be:
NEO
Grant Value 
Percent of 
Salary
Ms. Apsey
 250 %
Ms. Holloway
 175 %
Mr. Slocum
 140 %
Ms. Mason Soneral
 175 %
Ms. Tanner
 175 %
In July 2024, the Committee recommended to the Fortis Board of Directors approval of a special retention 
grant of SBUs to Ms. Holloway, based on a value of $600,000. The award vests 50% after three years and 50% 
after four years. The award was approved by the Fortis Board of Directors in July 2024 and it was granted on 
August 1, 2024. 
The amounts and more detailed terms of the 2024 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.
Table of Contents
94

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. 
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 will not be eligible for future equity-based 
compensation awards until the later of (i) the end of the one-year period commencing on the date of such failure 
Table of Contents
95

or (ii) such time as the executive is again in compliance with the guidelines. As of December 31, 2024, each of 
the NEOs was in compliance with this policy.
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
RONNIE D. HAWKINS, JR.
DAVID G. HUTCHENS
JAMES P. LAURITO
 A. DOUGLAS ROTHWELL
Table of Contents
96

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
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 
2022
 
864,999 
 
2,162,565 
 
1,385,730 
 
— 
 
150,088 
 
4,563,382 
Gretchen L. 
Holloway,
SVP & CFO
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 
2022
 
422,000 
 
738,532 
 
676,044 
 
— 
 
39,579 
 
1,876,155 
Brian Slocum,
SVP & COO
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
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 
2022
 
409,799 
 
717,154 
 
656,500 
 
— 
 
40,637 
 
1,824,090 
Krista Tanner,
President
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 
2022
 
370,900 
 
649,076 
 
594,182 
 
— 
 
36,726 
 
1,650,884 
____________________________
(1) The amounts reported in this column represent the grant date fair value of PBU awards and SBU awards 
granted to the NEOs in 2022 and 2023 under the Executive Omnibus Plan and the Fortis Inc. 2020 
Restricted Share Unit Plan, and in 2024 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 2024 PBU awards at the grant date assuming that the highest level of performance conditions 
will be achieved are as follows:
Ms. Apsey
$ 
3,120,000 
Ms. Holloway
 
1,044,633 
Mr. Slocum
 
874,720 
Ms. Mason Soneral
 
1,004,500 
Ms. Tanner
 
1,017,566 
(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 2024, 2023 and 2022. For information regarding the 
corporate goals for 2024, see “Compensation Discussion and Analysis - Key Components of Our NEO 
Compensation Program - Annual Corporate Performance Bonus." 
(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 
Table of Contents
97

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 5.57% for 
2022, 5.24% for 2023 and 5.76% for 2024. As of December 31, 2024, the cash balance interest crediting 
rate assumption changed from 4.47% for 2024 and 4.50% in all future years to 4.04% in 2025 and 4.50% 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 Ms. Apsey’s 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 2024, 2023 and 2022 are itemized in the table below.
Name
Year
401(k) Match
Personal Use 
of Company 
Aircraft
Relocation 
Expenses
Other 
Benefits
Total
Linda H. Apsey
2024
$ 
20,700 
$ 
72,964 
$ 
— $ 
31,385 $ 
125,049 
2023
 
19,800 
 
92,049 
 
—  
27,185  
139,034 
2022
 
18,300 
 
104,603 
 
—  
27,185  
150,088 
Gretchen L. Holloway
2024
 
20,700 
 
— 
 
—  
21,449  
42,149 
2023
 
19,800 
 
— 
 
—  
21,260  
41,060 
2022
 
18,300 
 
— 
 
—  
21,279  
39,579 
Brian Slocum
2024
 
20,176 
 
— 
 
—  
21,327  
41,503 
2023
 
19,800 
 
— 
 
—  
21,171  
40,971 
Christine Mason Soneral
2024
 
20,700 
 
— 
 
—  
21,789  
42,489 
2023
 
19,800 
 
— 
 
—  
20,500  
40,300 
2022
 
18,300 
 
— 
 
—  
22,337  
40,637 
Krista Tanner
2024
 
18,785 
 
— 
 
34,254  
21,434  
74,473 
2023
 
16,317 
 
— 
 
—  
45,297  
61,614 
2022
 
15,357 
 
— 
 
—  
21,369  
36,726 
Table of Contents
98

Grants of Plan-Based Awards
The following table sets forth information concerning each grant of an award made to a NEO during 2024.
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
1/1/2024
1/29/2024
SBU
$ 
— 
$ 
— 
$ 
— 
 
— 
 
— 
 
— 
 19,067 
$ 780,000 
1/1/2024
1/29/2024
PBU
 
— 
 
— 
 
— 
 
19,067 
 38,134 
 76,267 
 
— 
 1,560,000 
ACPB
 
— 
 936,000 
 1,872,000 
 
— 
 
— 
 
— 
 
— 
 
— 
Gretchen L. 
Holloway
1/1/2024
1/29/2024
SBU
 
— 
 
— 
 
— 
 
— 
 
— 
 
— 
 
6,384 
 
261,158 
1/1/2024
1/29/2024
PBU
 
— 
 
— 
 
— 
 
6,384 
 12,768 
 25,536 
 
— 
 
522,317 
8/1/2024
7/15/2024
SBU
 
— 
 
— 
 
— 
 
— 
 
— 
 
— 
 14,564 
 
600,000 
ACPB
 
— 
 447,700 
 895,400 
 
— 
 
— 
 
— 
 
— 
 
— 
Brian 
Slocum
1/1/2024
1/29/2024
SBU
 
— 
 
— 
 
— 
 
— 
 
— 
 
— 
 
5,346 
 
218,680 
1/1/2024
1/29/2024
PBU
 
— 
 
— 
 
— 
 
5,346 
 10,691 
 21,382 
 
— 
 
437,360 
ACPB
 
— 
 351,450 
 702,900 
 
— 
 
— 
 
— 
 
— 
 
— 
Christine 
Mason 
Soneral
1/1/2024
1/29/2024
SBU
 
— 
 
— 
 
— 
 
— 
 
— 
 
— 
 
6,139 
 
251,125 
1/1/2024
1/29/2024
PBU
 
— 
 
— 
 
— 
 
6,139 
 12,277 
 24,555 
 
— 
 
502,250 
ACPB
 
— 
 430,500 
 861,000 
 
— 
 
— 
 
— 
 
— 
 
— 
Krista 
Tanner
1/1/2024
1/29/2024
SBU
 
— 
 
— 
 
— 
 
— 
 
— 
 
— 
 
6,218 
 
254,392 
1/1/2024
1/29/2024
PBU
 
— 
 
— 
 
— 
 
6,218 
 12,437 
 24,874 
 
— 
 
508,783 
ACPB
 
— 
 535,000 
 1,070,000 
 
— 
 
— 
 
— 
 
— 
 
— 
____________________________
(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 Total 
Shareholder Return in comparison to the Total Shareholder Return during the performance period for each 
of the companies that comprise the 2024 Fortis peer group, (2) cumulative consolidated net income for 
each fiscal year during the performance period and (3) Fortis’ carbon reduction performance 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, 2024 are 
recorded with a fair value of $40.91 per share, and the SBUs with a grant date of August 1, 2024 are 
recorded with a fair value of $41.20 per share.
Performance-Based Unit Award Agreements
The PBU award agreements entered into with each NEO effective January 1, 2024 (the “PBU Grant Date”) 
(each a “PBU Agreement”) provide generally that the award will vest on January 1, 2027 (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 Total Shareholder Return 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 
Table of Contents
99

related to the Fortis Carbon Reduction Performance goal (the “CRP 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 Total Shareholder 
Return
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 Carbon Reduction 
Performance
8.2M tonnes
50% of CRP 
Target Units
7.9M tonnes
100% of CRP 
Target Units
7.1M tonnes
200% of CRP 
Target Units
The performance period for the award is January 1, 2024 through December 31, 2026 (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.
Total Shareholder Return of Fortis will be compared to each of the companies (the “Peer Companies”) listed 
in the Fortis Peer Group 2024 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
The Total Shareholder Return of Fortis and the Peer Companies shall be computed in U.S. dollars as follows:
A: Calculate the Market Price as of the first day of the Payment Criteria Period 
B: Calculate the Market Price as of the last day of the Payment Criteria Period 
C: Calculate the total dividends paid per share of its common stock (or equivalent security) during the 
Payment Criteria Period 
Total Shareholder Return = ((B - A) + C)/A, where Market Price is the 5-day volume weighted average price 
of Fortis Common Shares and the Payment Criteria Period is the 3-year performance period.
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 Carbon Reduction Performance goal will evaluate the target linked to Fortis’ achievement of a 
reduction in corporate-wide Scope 1 emissions over the Payment Criteria Period. 
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 
Table of Contents
100

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, grantee will forfeit the award.
“Retirement” is defined to mean termination of 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, 2024 (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, 2027 (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 
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 
Table of Contents
101

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 2024, we did not grant new awards of stock options, stock appreciation rights, or similar option-like 
instruments to our NEOs.
Table of Contents
102

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 2024 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
 
16,882 (2)
$ 
701,771  
— 
$ 
— 
 
29,373 (3)
 
1,221,031  
— 
 
— 
 
20,200 (4)
 
839,697  
82,818 (5)
 
3,442,731 
 
19,886 (6)
 
826,657  
79,544 (7)
 
3,306,629 
Gretchen L. 
Holloway
 
5,765 (2)
 
239,657  
— 
 
— 
 
10,031 (3)
 
416,994  
— 
 
— 
 
6,829 (4)
 
283,901  
28,002 (5)
 
1,164,031 
 
6,658 (6)
 
276,780  
26,633 (7)
 
1,107,120 
 
14,854 (8)
 
617,448  
— 
 
— 
Brian Slocum
 
4,372 (2)
 
181,730  
— 
 
— 
 
7,607 (3)
 
316,204  
— 
 
— 
 
5,354 (4)
 
222,576  
21,953 (5)
 
912,591 
 
5,575 (6)
 
231,761  
22,301 (7)
 
927,043 
Christine Mason 
Soneral
 
5,598 (2)
 
232,728  
— 
 
— 
 
9,741 (3)
 
404,915  
— 
 
— 
 
6,567 (4)
 
272,995  
26,926 (5)
 
1,119,299 
 
6,402 (6)
 
266,147  
25,609 (7)
 
1,064,586 
Krista Tanner
 
5,067 (2)
 
210,637  
— 
 
— 
 
8,816 (3)
 
366,476  
— 
 
— 
 
6,118 (4)
 
254,316  
25,083 (5)
 
1,042,710 
 
6,486 (6)
 
269,609  
25,943 (7)
 
1,078,434 
____________________________
(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, 2024 ($41.57).
(2) These unvested SBUs were granted in 2022 and vested on January 1, 2025. These SBU numbers include 
the original SBU grant plus dividend equivalent units earned.
(3) These unvested PBUs were granted in 2022 and earned with respect to the applicable performance 
measures during the three-year performance period started January 1, 2022 and ended December 31, 
2024. These PBU numbers include the original grant plus dividend equivalent units earned. Such PBUs 
vested on January 1, 2025, and the Committee certified the achievement of 87% of the applicable 
performance goals on February 4, 2025. 
(4) These unvested SBUs were granted in 2023 and vest on January 1, 2026. These SBU numbers include the 
original SBU grant plus dividend equivalent units earned.
(5) These unvested PBUs were granted in 2023 and generally vest on January 1, 2026. 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. 
Table of Contents
103

(6) These unvested SBUs were granted in 2024 and generally vest on January 1, 2027. These SBU numbers 
include the original SBU grant plus dividend equivalent units earned.
(7) 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.
(8) These unvested SBUs were granted in 2024 and vest on August 1, 2027 and August 1, 2028. These SBU 
numbers include the original SBU grant plus dividend equivalent units earned.
The 2022 and 2023 PBU grants made to NEOs were made pursuant to the Executive Omnibus Plan and the 
2022 and 2023 SBU grants made to NEOs were made pursuant to the Fortis Inc. 2020 Restricted Share Unit 
Plan. The 2024 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 2024:
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
 
19,130  (2) $ 
812,828 
 
56,246  (3)  
2,389,902 
Gretchen L. Holloway
 
6,559  (2)  
278,702 
 
19,286  (3)  
819,475 
Brian Slocum
 
1,879  (2)  
79,832 
 
5,525  (3)  
234,747 
Christine Mason Soneral
 
6,370  (2)  
270,646 
 
18,728  (3)  
795,769 
Krista Tanner
 
5,654  (2)  
240,251 
 
16,625  (3)  
706,415 
____________________________
(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 $42.49.
(2) Amounts reported reflect the vesting of SBUs granted January 1, 2021 and associated dividend equivalent 
units.
(3) Amounts reported reflect the vesting of PBUs granted January 1, 2021 and associated dividend equivalent 
units. The award contains performance conditions established by the Committee. The performance period 
ended on December 31, 2023. The Committee certified the achievement of 147% of the applicable 
performance goals on January 29, 2024. 
Table of Contents
104

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
 
30.59 
$ 
562,830 
N/A
ESRP Shift
 N/A  
39,810 
N/A
        Total Qualified Plan
 
602,640 
N/A
ESRP
 
21.83 
 
2,928,215 
N/A
Gretchen L. Holloway
Cash Balance Component
 
20.95 
 
379,842 
N/A
        Total Qualified Plan
 
379,842 
N/A
ESRP
 
9.91 
 
731,074 
N/A
Brian Slocum
Cash Balance Component
 
21.56 
 
377,411 
N/A
        Total Qualified Plan
 
377,411 
N/A
ESRP
 
13.91 
 
594,361 
N/A
Christine Mason Soneral
Cash Balance Component
 
17.29 
 
387,645 
N/A
        Total Qualified Plan
 
387,645 
N/A
ESRP
 
17.29 
 
1,128,407 
N/A
Krista Tanner
Cash Balance Component
 
10.14 
 
210,612 
N/A
        Total Qualified Plan
 
210,612 
N/A
ESRP
 
10.14 
 
575,395 
N/A
____________________________
(1) Credited service is estimated as of December 31, 2024 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, 2024 (the “measurement date” used for financial accounting purposes) of the benefit that 
was earned as of that date. Certain benefits are payable as an annuity only, not as a lump sum, and/or 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, 2024. The rate at which future 
expected benefit payments were discounted in calculating present values was 5.76%, the same rate used 
for fiscal year-end 2024 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 4.04% for 2025 and 4.50% thereafter.
We assumed no NEOs would die or become disabled prior to retirement or terminate employment with us 
prior to becoming eligible for benefits unreduced for early retirement. The assumed retirement age for each 
executive was generally the earliest age at which benefits unreduced for early retirement were available 
under the respective plans. For consistency, we generally use the same assumed retirement 
Table of Contents
105

commencement age for other benefits, including benefits expressed as an account value where the concept 
of benefit reductions for early retirement is not meaningful. The assumed retirement benefit commencement 
ages were 58 for each NEO.
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 ($345,000 
in 2024). 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 2024 is approximately $586,000, Ms. Holloway’s is approximately $419,000, Mr. 
Slocum’s is approximately $424,000, Ms. Mason Soneral’s is approximately $418,000, Ms. Tanner’s is 
approximately $231,000. 
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 2024, although previous shifts have continued to earn interest credits. As of year-
end 2024, her ESRP shift balance was approximately $41,000.
Table of Contents
106

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 
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, 2024, the ESRP account values, net of the 
amounts shifted to the Qualified Plan, are as follows:
Ms. Apsey
$ 
3,048,752 
Ms. Holloway
 
806,527 
Mr. Slocum
 
667,589 
Ms. Mason Soneral
 
1,217,833 
Ms. Tanner
 
630,361 
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 2024 plan year 
and elected to have 10% of his 2024 salary deferred into the plan. During the enrollment for the 2023 plan year, 
Mr. Slocum elected to defer 35% of his bonus earned in 2023 and paid in 2024. The following table reports 
amounts contributed in 2024, together with aggregate earnings on contributions and withdrawals or distributions 
on contributions in 2024, under the plan. For the year ended December 31, 2024, the investment options 
available under the plan generated annual returns ranging from 4.7% to 42.6%.
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
$ 
145,997 
$ 
— 
$ 
146,180 
$ 
— 
$ 
1,215,256 
____________________________
(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, 2024. 
Table of Contents
107

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 
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, 2024.
The employment agreements provide that each NEO will receive an annual base salary equal to their 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 contender 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
Table of Contents
108

◦
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;
•
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.
Table of Contents
109

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, 2024.
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
$ 
— 
$ 
— 
$ 1,872,000 
$ 4,375,163 
$ 
— 
$ 
— 
  Target Short-term 
Bonus
 
— 
 
— 
 
— 
 
— 
 
936,000 
 
936,000 
  Pro Rata Short-term 
(Annual) Incentive 
Comp
 
— 
 
— 
 
1,684,800 
 
1,684,800 
 
— 
 
— 
  Service-Based Unit 
Awards (5)
 
2,368,125 
 
— 
 
2,368,125 
 
2,368,125 
 
2,368,125 
 
2,368,125 
  Performance-Based 
Unit Awards (6)
 
4,553,726 
 
— 
 
4,553,726 
 
4,736,179 
 
4,553,726 
 
4,553,726 
Benefits and 
Outplacement
  Retirement Plan
 
— 
 
— 
 
— 
 
— 
 
— 
 
24,807 
  ESRP
 
— 
 
— 
 
— 
 
— 
 
— 
 
120,537 
  Outplacement
 
— 
 
— 
 
25,000 
 
25,000 
 
— 
 
— 
  Health & Welfare 
Benefits
 
— 
 
— 
 
96,605 
 
96,605 
 
— 
 
— 
  Postretirement Welfare 
Plan (7)
 
598,624 
 
598,624 
 
598,624 
 
598,624 
 
598,624 
 
— 
Total Payout:
$ 7,520,475 
$ 
598,624 
$ 11,198,880 
$ 13,884,496 
$ 8,456,475 
$ 8,003,195 
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
$ 
— 
$ 
— 
$ 
895,400 
$ 2,115,155 
$ 
— 
$ 
— 
  Target Short-term 
Bonus
 
— 
 
— 
 
— 
 
— 
 
447,700 
 
447,700 
  Pro Rata Short-term 
(Annual) Incentive 
Comp
 
— 
 
— 
 
805,860 
 
805,860 
 
— 
 
— 
  Service-Based Unit 
Awards (5)
 
— 
 
— 
 
487,343 
 
1,417,786 
 
1,417,786 
 
1,417,786 
  Performance-Based 
Unit Awards (6)
 
— 
 
— 
 
563,067 
 
1,600,684 
 
1,538,374 
 
1,538,374 
Benefits and 
Outplacement
  Retirement Plan
 
— 
 
— 
 
— 
 
— 
 
— 
 
39,202 
  ESRP
 
— 
 
— 
 
— 
 
— 
 
— 
 
75,453 
  Outplacement
 
— 
 
— 
 
25,000 
 
25,000 
 
— 
 
— 
  Health & Welfare 
Benefits
 
— 
 
— 
 
96,605 
 
96,605 
 
— 
 
— 
Total Payout:
$ 
— 
$ 
— 
$ 2,873,275 
$ 6,061,090 
$ 3,403,860 
$ 3,518,515 
Table of Contents
110

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
$ 
— 
$ 
— 
$ 
937,200 
$ 1,520,671 
$ 
— 
$ 
— 
  Target Short-term 
Bonus
 
— 
 
— 
 
— 
 
— 
 
351,450 
 
351,450 
  Pro Rata Short-term 
(Annual) Incentive Comp
 
— 
 
— 
 
632,610 
 
632,610 
 
— 
 
— 
  Service-Based Unit 
Awards (5)
 
— 
 
— 
 
225,637 
 
636,067 
 
636,067 
 
636,067 
  Performance-Based 
Unit Awards (6)
 
— 
 
— 
 
451,285 
 
1,272,141 
 
1,224,892 
 
1,224,892 
  280G Cutback
 
— 
 
— 
 
— 
 
(501,870)  
— 
 
— 
Benefits and 
Outplacement
  Retirement Plan
 
— 
 
— 
 
— 
 
— 
 
— 
 
46,499 
  ESRP
 
— 
 
— 
 
— 
 
— 
 
— 
 
73,228 
  Outplacement
 
— 
 
— 
 
25,000 
 
25,000 
 
— 
 
— 
  Health & Welfare 
Benefits
 
— 
 
— 
 
64,403 
 
64,403 
 
— 
 
— 
Total Payout:
$ 
— 
$ 
— 
$ 2,336,135 
$ 3,649,022 
$ 2,212,409 
$ 2,332,136 
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
$ 
— 
$ 
— 
$ 
861,000 
$ 2,042,436 
$ 
— 
$ 
— 
  Target Short-term 
Bonus
 
— 
 
— 
 
— 
 
— 
 
430,500 
 
430,500 
  Pro Rata Short-term 
(Annual) Incentive Comp
 
— 
 
— 
 
774,900 
 
774,900 
 
— 
 
— 
  Service-Based Unit 
Awards (5)
 
— 
 
— 
 
270,712 
 
771,870 
 
771,870 
 
771,870 
  Performance-Based 
Unit Awards (6)
 
— 
 
— 
 
541,431 
 
1,543,713 
 
1,483,208 
 
1,483,208 
Benefits and 
Outplacement
  Retirement Plan
 
— 
 
— 
 
— 
 
— 
 
— 
 
30,721 
  ESRP
 
— 
 
— 
 
— 
 
— 
 
— 
 
89,426 
  Outplacement
 
— 
 
— 
 
25,000 
 
25,000 
 
— 
 
— 
  Health & Welfare 
Benefits
 
— 
 
— 
 
96,605 
 
96,605 
 
— 
 
— 
Total Payout:
$ 
— 
$ 
— 
$ 2,569,648 
$ 5,254,524 
$ 2,685,578 
$ 2,805,725 
Table of Contents
111

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
$ 
— 
$ 
— 
$ 1,070,000 
$ 2,139,935 
$ 
— 
$ 
— 
  Target Short-term 
Bonus
 
— 
 
— 
 
— 
 
— 
 
535,000 
 
535,000 
  Pro Rata Short-term 
(Annual) Incentive Comp
 
— 
 
— 
 
963,000 
 
963,000 
 
— 
 
— 
  Service-Based Unit 
Awards (5)
 
— 
 
— 
 
259,414 
 
734,561 
 
399,838 
 
399,838 
  Performance-Based 
Unit Awards (6)
 
— 
 
— 
 
518,832 
 
1,469,094 
 
763,149 
 
763,149 
Benefits and 
Outplacement
  Retirement Plan
 
— 
 
— 
 
— 
 
— 
 
— 
 
20,119 
  ESRP
 
— 
 
— 
 
— 
 
— 
 
— 
 
54,966 
  Outplacement
 
— 
 
— 
 
25,000 
 
25,000 
 
— 
 
— 
  Health & Welfare 
Benefits
 
— 
 
— 
 
64,365 
 
64,365 
 
— 
 
— 
Total Payout:
$ 
— 
$ 
— 
$ 2,900,611 
$ 5,395,955 
$ 1,697,987 
$ 1,773,072 
____________________________
(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 $501,870 (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. In the 
case of Death, Disability or, for SBUs granted prior to 2023, Retirement termination and, in each case, 15 
years or more of service with the Company or its Affiliates, the outstanding and unvested SBU awards and 
respective dividend equivalents shall be deemed vested and redeemable on the date of the death or on the 
date on which the grantee’s service is terminated due to Disability or Retirement. In the case of Death, 
Disability or, for SBUs granted prior to 2023, Retirement termination and less than 15 years of service with 
the Company or its Affiliates, the outstanding and unvested SBU awards and respective dividend 
equivalents shall be deemed to have vested pro-rata based on the continued service through the first and 
second anniversaries of the grant, earning 1/3 or 2/3 of the original award and redeemable on the date of 
the death or on the date on which the grantee’s service is terminated due to Disability or Retirement. For the 
SBUs granted in 2023 and later, in the case of Death or Disability termination, outstanding and unvested 
Table of Contents
112

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 granted in 2023 and later, 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 granted in 2023 and later, 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. In the case of Cause, Voluntary Termination and, 
for SBU awards granted prior to 2023, Involuntary Termination Without Cause, outstanding and unvested 
SBU awards and respective dividend equivalents shall be deemed to be forfeited.
(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 (a) for PBU awards 
granted prior to 2023, the anniversary date of the grant, and the grantee will receive, (i) one-third of the 
number of PBUs to which the grantee would have otherwise been entitled if the grantee had remained an 
employee through the PBU Vesting Date shall be deemed to have vested on the PBU Vesting Date if 
termination occurred on or after the one-year anniversary of the PBU Grant Date and before the two-year 
anniversary of the PBU Grant Date, and (ii) two-thirds of the number of PBUs to which the grantee would 
have otherwise been entitled if the grantee had remained an employee through the PBU Vesting Date shall 
be deemed to have vested on the PBU Vesting Date if termination occurred on or after the two-year 
anniversary of the PBU Grant Date but before the PBU Vesting Date and (b) for PBU awards granted in 
2023 or later, the period served from grant date to termination and redeemable on the PBU Vesting Date. 
For the PBU awards granted in 2023 or later, 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 2023 and 2024 
awards as an estimate of potential payments and actual performance of 87% for the 2022 awards. In the 
case of Cause, Voluntary Termination and, for PBU awards granted in 2022 due to Involuntary Termination 
Without Cause, outstanding and unvested PBU awards and respective dividend equivalents shall be 
deemed to be forfeited.
(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 5.86%, the same rate 
used for fiscal year-end 2024 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:
Table of Contents
113

For 2024, our last completed fiscal year:
the median of the annual total compensation of all employees of the Company (other than Ms. 
Apsey), was $188,846; and
the annual total compensation of Ms. Apsey as reported in the Summary Compensation Table was 
$5,388,526.
Based on this information, Ms. Apsey’s 2024 annual total compensation was estimated to be 29 times the 
median annual total compensation for all employees, other than Ms. Apsey.
We determined that, as of December 31, 2023, our employee population consisted of 747 individuals with all 
of those individuals located in the United States. To identify the “median employee” from our employee 
population, excluding Ms. Apsey, we utilized a consistently applied compensation measure that included the 
sum of each employee’s 2023 annualized base salary as of December 31, 2023 as reflected in our payroll 
records, and target 2023 awards made under our ACPB plan, 2017 Omnibus Plan, Executive Omnibus Plan 
and Fortis Inc. 2020 Restricted Share Unit Plan that were not paid in 2023. We arrayed these values to select 
our “median employee.”
Under Item 402(u), a company is permitted to identify its “median employee” once every three years if there 
has been no significant change to its employee population or employee compensation arrangements that would 
result in a significant change to its pay ratio disclosure. We updated our “median employee” for 2023 as it had 
been three years since we had last identified the “median employee” for this analysis.
Using our “median employee” and Ms. Apsey, we calculated the applicable Summary Compensation Table 
values for each according to applicable SEC rules.
Director Compensation
The following table provides information concerning the compensation of each person who served as a non-
employee director of the Company during 2024.
Non-Employee Director Compensation Table
Name
Fees Earned or 
Paid in Cash ($) (1)
Total ($)
(a)
(b)
(h)
Leanne M. Bell
$ 
155,000 
$ 
155,000 
Robert A. Elliott
175,000
175,000
Geoffrey S. Chatas
23,680
23,680
Debora Frodl
167,500
167,500
Ronnie 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
23,680
23,680
____________________________
(1) Includes annual Board retainer and committee chairmanship retainer, as well as a chairperson fee (for Ms. 
Pierce only). The retainers for Messrs. Chatas and Walker reflect their service on our Board of Directors 
from their appointments in November 2024 through December 31, 2024.
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.
Table of Contents
114

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. None of the directors participated in this plan in 2024.
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, 2025, 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.
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, 2025 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
 
—  
— 
 
5,042 
*
Christine Mason Soneral
 
—  
— 
 
— 
 — 
Krista Tanner
 
—  
— 
 
10,693 
*
Simon Whitelocke
 
—  
— 
 
8,959 
*
Leanne M. Bell
 
—  
— 
 
— 
 — 
Geoffrey S. Chatas
 
—  
— 
 
— 
 — 
Robert A. Elliott
 
—  
— 
 
— 
 — 
Debora Frodl
 
—  
— 
 
— 
 — 
Ronnie Hawkins
 
—  
— 
 
— 
 — 
David G. Hutchens
 
—  
— 
 
127,963 
*
James P. Laurito
 
—  
— 
 
19,503 
*
Jocelyn H. Perry
 
—  
— 
 
262,292 
*
Sandra E. Pierce
 
—  
— 
 
— 
 — 
Kevin L. Prust
 
—  
— 
 
500 
*
A. Douglas Rothwell
 
—  
— 
 
— 
 — 
Brian C. Walker
 
—  
— 
 
— 
 — 
All current directors and executive officers as a group 
(18 persons)
 
— 
 — %  
497,744 
*
* 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, 2024, there were no securities authorized for issuance under any compensation plans of 
ITC Holdings.
Table of Contents
115

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 
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, 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).
Mr. Elliott served on the board of directors of UNS Energy Corporation, a wholly-owned subsidiary of 
FortisUS. When determining Mr. Elliott’s independence, the board and shareholders agreed to waive the 
requirements set forth in the definition of independent director under the Shareholders Agreement which states 
that a director is not and during the three years prior to being designated as a director of the Company has not 
served as a director of FortisUS or any of its affiliates.
Table of Contents
116

ITEM 14.  PRINCIPAL ACCOUNTANT FEES AND SERVICES.
The following table provides a summary of the aggregate fees incurred for Deloitte’s services in 2024 and 
2023:
2024
2023
Audit fees (1)
$ 
2,459,000 $ 
2,377,000 
Audit-related fees (2)
 
67,000  
113,000 
Tax fees (3)
 
12,000  
7,000 
All other fees (4)
 
11,000  
14,000 
Total fees
$ 
2,549,000 $ 
2,511,000 
____________________________
(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 and services provided in connection with 
certain debt related reporting.
(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.
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 2024 pursuant to the 
pre-approval policy.
Table of Contents
117

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, 2024 and 2023
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2024, 2023 and 2022
Consolidated Statements of Changes in Stockholder's Equity for the Years Ended December 31, 2024, 2023 
and 2022
Consolidated Statements of Cash Flows for the Years Ended December 31, 2024, 2023 and 2022
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
The following exhibits are filed as part of this report or filed previously and incorporated by reference 
to the filing indicated. Our SEC file number is 001-32576.
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
Eleventh 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)
Table of Contents
118

 
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)
Table of Contents
119

 
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).
Table of Contents
120

 
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)
*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)
Table of Contents
121

*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)
Table of Contents
122

*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.
**19
ITC Holdings Corp. Insider Trading Policies and Procedures
**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, 
2024 (formatted in Inline XBRL and contained in Exhibit 101)
___________________________
*
Management contract or compensatory plan or arrangement
**
Filed herewith
Table of Contents
123

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)
2024
2023
ASSETS
Current assets
Cash and cash equivalents
$ 
16 
$ 
325 
Accounts receivable from subsidiaries
 
20 
 
21 
Intercompany tax receivable from subsidiaries
 
21 
 
19 
Prepaid and other current assets
 
5 
 
1 
Total current assets
 
62 
 
366 
Other assets
Investment in subsidiaries
 
6,872 
 
6,431 
Deferred income taxes
 
65 
 
66 
Other assets
 
136 
 
125 
Total other assets
 
7,073 
 
6,622 
TOTAL ASSETS
$ 
7,135 
$ 
6,988 
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities
Accrued compensation
$ 
57 
$ 
59 
Accrued interest
 
34 
 
38 
Debt maturing within one year
 
— 
 
400 
Other current liabilities
 
17 
 
14 
Total current liabilities
 
108 
 
511 
Accrued pension and postretirement liabilities
 
39 
 
42 
Long-term debt (net of deferred financing fees and discount of $22 and $22, respectively)
 
3,878 
 
3,478 
Other liabilities
 
113 
 
95 
TOTAL LIABILITIES
 
4,138 
 
4,126 
STOCKHOLDER’S EQUITY
Common stock, without par value, 235,000,000 shares authorized, 224,203,112 shares issued and 
outstanding at December 31, 2024 and 2023
 
892 
 
892 
Retained earnings
 
2,077 
 
1,941 
Accumulated other comprehensive income
 
28 
 
29 
Total stockholder’s equity
 
2,997 
 
2,862 
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY
$ 
7,135 
$ 
6,988 
See notes to condensed financial statements (parent company only).
Table of Contents
124

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)
2024
2023
2022
Other (expenses) income, net
$ 
13 
$ 
13 
$ 
(5) 
General and administrative expense
 
(11)  
(10)  
(8) 
Taxes other than income taxes
 
(1)  
— 
 
— 
Interest expense, net
 
(175)  
(161)  
(135) 
LOSS BEFORE INCOME TAXES
 
(174)  
(158)  
(148) 
INCOME TAX BENEFIT
 
(46)  
(29)  
(35) 
LOSS AFTER TAXES
 
(128)  
(129)  
(113) 
EQUITY IN SUBSIDIARIES’ NET EARNINGS
 
612 
 
592 
 
555 
NET INCOME
 
484 
 
463 
 
442 
OTHER COMPREHENSIVE (LOSS) INCOME
Derivative instruments (net of tax of $(1), $1 and $12, respectively)
 
(1)  
2 
 
29 
TOTAL OTHER COMPREHENSIVE (LOSS) INCOME, NET OF TAX
 
(1)  
2 
 
29 
TOTAL COMPREHENSIVE INCOME
$ 
483 
$ 
465 
$ 
471 
See notes to condensed financial statements (parent company only).
Table of Contents
125

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)
2024
2023
2022
CASH FLOWS FROM OPERATING ACTIVITIES
Net income
$ 
484 
$ 
463 
$ 
442 
Adjustments to reconcile net income to net cash used in operating activities:
Equity in subsidiaries' earnings
 
(612)  
(592)  
(555) 
Dividends from subsidiaries
 
60 
 
128 
 
88 
Deferred and other income taxes
 
(99)  
(90)  
(41) 
Net intercompany tax payments from subsidiaries
 
101 
 
113 
 
82 
Share-based compensation
 
4 
 
6 
 
3 
Other
 
(10)  
4 
 
50 
Changes in assets and liabilities, exclusive of changes shown separately:
Accounts receivable from subsidiaries
 
1 
 
(2)  
2 
Intercompany tax receivable from subsidiaries
 
(2)  
7 
 
(10) 
Accrued compensation
 
(3)  
(4)  
(13) 
Other current and non-current assets and liabilities, net
 
5 
 
6 
 
2 
Net cash (used in) provided by operating activities
 
(71)  
39 
 
50 
CASH FLOWS FROM INVESTING ACTIVITIES
Equity contributions to subsidiaries
 
(189)  
(58)  
(58) 
Return of capital from subsidiaries
 
295 
 
223 
 
185 
Proceeds from repayment of advances to subsidiaries
 
— 
 
4 
 
50 
Other
 
4 
 
— 
 
2 
Net cash provided by investing activities
 
110 
 
169 
 
179 
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt, net
 
399 
 
799 
 
600 
Borrowings under revolving credit agreements
 
— 
 
16 
 
89 
Net repayment of commercial paper
 
— 
 
(134)  
(21) 
Repayment of long-term debt
 
(400)  
(250)  
(500) 
Repayments of revolving credit agreements
 
— 
 
(26)  
(118) 
Dividends to ITC Investment Holdings
 
(343)  
(283)  
(273) 
Other
 
(4)  
(7)  
(6) 
Net cash (used in) provided by financing activities
 
(348)  
115 
 
(229) 
NET (DECREASE) INCREASE IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH
 
(309)  
323 
 
— 
CASH, CASH EQUIVALENTS AND RESTRICTED CASH — Beginning of period
 
326 
 
3 
 
3 
CASH, CASH EQUIVALENTS AND RESTRICTED CASH — End of period
$ 
17 
$ 
326 
$ 
3 
See notes to condensed financial statements (parent company only).
Table of Contents
126

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, 2024 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, 2024, the maturities of our debt outstanding were as follows:
(In millions of USD)
2025
$ 
— 
2026
 
400 
2027
 
1,400 
2028
 
— 
2029
 
— 
2030 and thereafter
 
2,100 
Total
$ 
3,900 
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 was $3,806 million and $3,792 million at December 31, 2024 and 2023, 
respectively. The total book value of the ITC Holdings long-term debt and debt maturing within one year, net of 
discount and deferred financing fees, was $3,878 million at December 31, 2024 and 2023. 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. 
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.
Table of Contents
127

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. We received principal and interest payments of $4 million and less than $1 million for 
the years ended December 31, 2023 and 2022, respectively, from subsidiaries associated with intercompany 
loans. There were no intercompany loans outstanding at December 31, 2024 and 2023.
Intercompany Tax Sharing Arrangement
We file consolidated income tax returns that include our affiliates, which are taxed as a corporation for 
federal and Michigan income tax purposes. We operate under an intercompany tax sharing arrangement with 
our subsidiaries and as a result may receive or pay federal and state income tax 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)
2024
2023
2022
Cash and cash equivalents
$ 
16 $ 
325 $ 
2 
Restricted cash included in other non-current assets
 
1  
1  
1 
Total cash, cash equivalents and restricted cash
$ 
17 $ 
326 $ 
3 
Supplementary Cash Flows Information
Year Ended December 31,
(In millions of USD)
2024
2023
2022
Interest paid
$ 
176 $ 
150 $ 
121 
Income taxes paid (a)
 
54  
49  
11 
____________________________
(a) Includes amounts paid to ITC Investment Holdings under a tax sharing agreement. Payments made directly 
to certain state jurisdictions were $1 million for the year ended December 31, 2024 and less than $1 million 
for each of the years ended December 31, 2023 and 2022.
Table of Contents
128

ITEM 16.  FORM 10-K SUMMARY.
Not applicable.
Table of Contents
129

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 13, 2025.
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 13, 2025
Linda H. Apsey
(principal executive officer)
 
/s/ GRETCHEN L. HOLLOWAY
Senior Vice President and Chief Financial Officer
February 13, 2025
Gretchen L. Holloway
 (principal financial and accounting officer)
 
/s/ SANDRA E. PIERCE
Director and Chairman
February 13, 2025
Sandra E. Pierce
/s/ LEANNE M. BELL
Director
February 13, 2025
Leanne M. Bell
/s/ GEOFFREY CHATAS
Director
February 13, 2025
Geoffrey Chatas
 
/s/ ROBERT A. ELLIOTT
Director
February 13, 2025
Robert A. Elliott
/s/ DEBORA M. FRODL
Director
February 13, 2025
Debora M. Frodl
/s/ RONNIE D. HAWKINS, JR
Director
February 13, 2025
Ronnie D. Hawkins, Jr
/s/ DAVID G. HUTCHENS
Director
February 13, 2025
David G. Hutchens
/s/ JAMES P. LAURITO
Director
February 13, 2025
James P. Laurito
 
/s/ JOCELYN H. PERRY
Director
February 13, 2025
Jocelyn H. Perry
 
/s/ KEVIN L. PRUST
Director
February 13, 2025
Kevin L. Prust
/s/ A. DOUGLAS ROTHWELL
Director
February 13, 2025
A. Douglas Rothwell
/s/ BRIAN WALKER
Director
February 13, 2025
Brian Walker
130