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, 2022
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
(State or Other Jurisdiction of Incorporation or Organization)
32-0058047
(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
None
Trading Symbol(s)
None
Name of Each Exchange on Which Registered
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.
*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.
Yes o No þ
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
o
Accelerated
filer
o
Non-accelerated
filer
þ
Smaller reporting
company
o
Emerging growth
company
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
o
Section 13(a) of the Exchange Act.
Table of Contents
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
o
audit report.
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
o
statements.
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
o
relevant recovery period pursuant to §240.10D-1(b).
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).
The aggregate market value of the registrant’s common stock held by non-affiliates on June 30, 2022 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 9, 2023.
Yes o No þ
None.
DOCUMENTS INCORPORATED BY REFERENCE
Table of Contents
ITC Holdings Corp.
Form 10-K for the Fiscal Year Ended December 31, 2022
INDEX
PART I
Item 1.
Business
Item 1A.
Risk Factors
Item 1B.
Unresolved Staff Comments
Item 2.
Item 3.
Item 4.
PART II
Item 5.
Item 6.
Item 7.
Properties
Legal Proceedings
Mine Safety Disclosures
Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases
of Equity Securities
[Reserved]
Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 8.
Item 9.
Financial Statements and Supplementary Data
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A.
Controls and Procedures
Item 9B. Other Information
Item 9C. Disclosure Regarding Foreign Jurisdictions That Prevent Inspections
PART III
Item 10.
Directors, Executive Officers and Corporate Governance
Item 11.
Executive Compensation
Item 12.
Item 13.
Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters
Certain Relationships and Related Transactions, and Director Independence
Item 14.
Principal Accountant Fees and Services
PART IV
Item 15.
Item 16.
Signatures
Exhibits and Financial Statement Schedules
Form 10-K Summary
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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. and not any of its subsidiaries;
• “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;
• “ADIT” are references to accumulated deferred income tax;
• “AFUDC” are references to an allowance for funds used during construction;
• “ALJ” are references to an administrative law judge;
• “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);
• “CIA” are references to the Coordination and Interconnection Agreement entered into by ITCTransmission
and DTE Electric dated as of February 28, 2003;
• “Consumers Energy” are references to Consumers Energy Company, a wholly-owned subsidiary of CMS
Energy Corporation;
• “COVID-19” are references to the Coronavirus disease that the World Health Organization declared a
pandemic in March 2020;
• “D.C. Circuit Court” are references to the U.S. Court of Appeals for the District of Columbia Circuit;
• “DCF” are references to discounted cash flow;
• “DOE” are references to the Department of Energy;
• “DTE Electric” are references to DTE Electric Company, a wholly-owned subsidiary of DTE Energy;
• “DTE Energy” are references to DTE Energy Company;
• “DTIA” are references to the Distribution-Transmission Interconnection Agreement entered into by ITC
Midwest and IP&L dated as of December 17, 2007 and amended and restated effective as of December
1, 2016;
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• “DT Interconnection Agreement” are references to the Amended and Restated Distribution-Transmission
Interconnection Agreement entered into by METC and Consumers Energy dated April 1, 2001 and most
recently amended and restated effective as of January 1, 2015;
• “Easement Agreement” are references to the Amended and Restated Easement Agreement entered into
by METC and Consumers Energy dated April 29, 2002 and as further supplemented;
• “Eiffel” are references to Eiffel Investment Pte Ltd, a private limited company duly organized and validly
existing under the laws of Singapore that is the GIC subsidiary that is a minority investor in ITC
Investment Holdings and successor to Finn Investment Pte Ltd;
• “ESPP” are references to the Fortis Amended and Restated 2012 Employee Share Purchase Plan;
• “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;
• “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;
• “ISO” are references to Independent System Operators;
• “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);
• “kW” are references to kilowatts (one kilowatt equaling 1,000 watts);
• “LBA” are references to a Local Balancing Authority;
• “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;
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• “LIBOR” are references to the London Interbank Offered Rate;
• “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;
• “Moody’s” are references Moody’s Investor Service, Inc.;
• “MVPs” are references to multi-value projects, which have been determined by MISO to have regional
value while meeting near-term system needs;
• “MW” are references to megawatts (one megawatt equaling 1,000,000 watts);
• “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;
• “November 2019 Order” are references to an order issued by the FERC on November 21, 2019 regarding
MISO ROE Complaints;
• “NYSE” are references to the New York Stock Exchange;
• “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;
• “PCBs” are references to polychlorinated biphenyls;
• “ROE” are references to return on equity;
• “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;
• “September 2016 Order” are references to an order issued by the FERC on September 28, 2016
regarding the Initial Complaint;
• “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;
• “SOFR” are references to the Secured Overnight Financing Rate;
• “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;
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• “S&P” are references to S&P Global Ratings;
• “Sunflower” are references to Sunflower Electric Company LLC;
• “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;
• “ULCS” are references to Utility Lines Construction Services, LLC; and
• “USD” are references to the United States dollar
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ITEM 1.
BUSINESS.
Overview
PART I
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 our economy and lifestyles 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 and operate high-voltage electric
transmission systems in Michigan’s Lower Peninsula and portions of Iowa, Minnesota, Illinois, Missouri, Kansas
and Oklahoma that transmit electricity from generating stations to local distribution facilities connected to our
transmission systems. In addition, we have electric transmission system assets under construction in
Wisconsin.
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 5 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. 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.
We expect to invest approximately $4.5 billion from 2023 through 2027 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) interconnect new
renewable generation resources; (3) upgrade physical and technological grid security to protect critical
infrastructure; and (4) expand access to electricity markets to reduce the overall cost of delivered energy to
customers.
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
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
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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 MISO Regulated Operating Subsidiaries and
ITC Great Plains.
Engineering
The Engineering group is composed of the Design, Capital Projects and Asset Management teams. The
Engineering group works with outside contractors to perform various aspects of our design, construction and
maintenance, 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.
Design — The Design team is responsible for the design of our transmission systems and setting the
standards for equipment used on our systems.
Capital Projects — The Capital Projects team is responsible for project and construction management for
capital projects and associated forecasting, which includes the construction of new transmission infrastructure
as well as asset renewal projects.
Asset Management — The Asset Management team performs the following activities:
• manages our vegetation management program;
• provides engineering technical support to the field;
• specifies, maintains and troubleshoots substation and transmission line assets as well as the protection
and control systems that are used to protect and monitor our transmission infrastructure; and
• develops and tracks 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, which is a division of Asplundh Tree Expert Co., to perform the majority of their
maintenance. The agreement with ULCS provides us with access to an experienced and scalable workforce
with knowledge of our system at an established rate.
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Safety, Protection and Preparedness
The Safety, Protection and Preparedness group 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 electricity 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 ITC’s reputation and brand by securing critical infrastructure,
data, and computing systems from threat actors. We protect vital infrastructure by developing, refining, and
continually delivering a comprehensive cyber security program while helping our stakeholders meet their
business objectives. As the threat landscape becomes increasingly sophisticated and expansive, we continue to
evolve our defensive strategy. We improve this strategy by deploying new technology, continuing education of
our user community, and advancing our protections against ongoing cyber threats. We leverage threat
intelligence and external industry practices for continuous improvement and refinement of our cyber security
program.
Real Time Operations
System Operations — From our operations facilities 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 analysis to plan for contingencies and maintain security
and reliability following any unplanned events on the system. 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.
Local Balancing Authority Operator — Under the functional control of MISO, ITCTransmission and METC
operate their electric transmission systems as a combined LBA area, known as MECS. From our operations
facilities in Michigan, our employees perform the LBA functions as outlined in MISO’s Balancing Authority
Agreement. These functions include actual interchange data administration and verification as well as MECS
LBA area emergency procedure implementation and coordination. Besides ITCTransmission and METC, our
other Regulated Operating Subsidiaries are not responsible for LBA 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
that
ITCTransmission and DTE Electric. The MOA
ITCTransmission provides to DTE Electric and certain generation-based support services that DTE Electric is
required to provide to ITCTransmission.
identifies control area coordination services
Generator Interconnection and Operation Agreement. The GIOA established, re-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.
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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 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.
Interconnection Agreement. The Generator
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, re-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. The OSA provides that when ITC Midwest upgrades 34.5 kV facilities to higher operating voltages it
may notify IP&L of the change and the OSA is no longer applicable to those facilities.
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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, and the MVPs. Additionally, certain projects at ITC Great Plains are eligible for recovery
through a region-wide charge in 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.
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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 Board has the power of supervision 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 Board is vested with the power of
condemnation in Iowa to the extent the Iowa Utilities Board 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 or upgrades of 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
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 or 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
Because 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.
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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, as discussed in “Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cost-Based
Formula Rates with True-Up Mechanism,” mitigate the seasonality of net income for our Regulated Operating
Subsidiaries. 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.
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 21.0%, 24.0% and 25.4%, respectively, of our consolidated billed revenues for the
year ended December 31, 2022. These customers, together and individually, consistently represent a significant
percentage of our operating revenue. This portion of total billed revenues of DTE Electric, Consumers Energy
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and IP&L include the collection of 2020 revenue accruals and deferrals and exclude any amounts for the 2022
revenue accruals and deferrals that were included in our 2022 operating revenues but will not be billed to our
customers until 2024. Refer to “Item 7. Management’s Discussion and Analysis of Financial Condition and
Results of Operations — Cost-Based Formula Rates with True-Up Mechanism” 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, 2022, we had 726 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 benefits for all of
our employees and various professional development opportunities through internal and external programs.
We strive to provide an inclusive and diverse environment for all of our employees. We believe that by
recognizing and valuing our employees’ similarities, as well as their differences, we make our shared goals
possible. In addition to our internal commitments to inclusion and diversity, we are continuing to enhance our
supplier diversity program. This effort will further diversify our supplier base through the recruitment and growth
of businesses owned by minorities, women and veterans.
Environmental Matters
See “Environmental Matters” in Note 16 to the consolidated financial statements.
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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. All of our
reports filed pursuant to Section 13(a) or 15(d) of the Exchange Act, including our annual reports on Form 10-K,
quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports, can be
accessed free of charge through our website. These reports are available as soon as practicable after they are
electronically filed with the SEC. The information on our website is not incorporated by reference into this report.
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 16 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;
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•
•
•
•
•
•
•
variances between estimated and actual costs of construction contracts awarded;
our ability to obtain financing for such expenditures, if necessary;
limitations on the amount of construction that can be undertaken on our system or transmission
systems owned by others at any one time;
regulatory requirements relating to our rate construct, including our ability to recover costs;
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 of 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. Congress periodically considers
enacting energy legislation that could assign new responsibilities to the FERC, modify provisions of the FPA or
provide the FERC or another entity with increased authority to regulate transmission matters. Our Regulated
Operating Subsidiaries may be affected by any such changes in federal energy laws, regulations or policies in
the future. While our Regulated Operating Subsidiaries are subject to the FERC’s exclusive jurisdiction for
purposes of rate regulation, changes in state laws affecting other matters, such as transmission siting and
construction, could limit investment opportunities available to us.
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Each of our MISO Regulated Operating Subsidiaries depends on its primary customer for a
substantial portion of its revenues, and any material failure by those primary customers to make
payments for transmission services could have a material adverse effect on our business, financial
condition, results of operations and cash flows.
Each of ITCTransmission, METC and ITC Midwest derive a substantial portion of their revenues from the
transmission of electricity to the local distribution facilities of DTE Electric, Consumers Energy and IP&L,
respectively. Each of these customers is expected to constitute the majority of the revenues of the respective
MISO Regulated Operating Subsidiary for the foreseeable future. Any material failure by DTE Electric,
Consumers Energy or IP&L to make payments for transmission services could have an adverse effect on our
business, financial condition, results of operations and cash flows.
A significant amount of the land on which our assets are located is subject to easements, mineral
rights and other similar encumbrances. As a result, we must comply with the provisions of various
easements, mineral rights and other similar encumbrances, which may adversely impact our ability to
complete construction projects in a timely manner.
METC does not own the majority of the land on which its electric transmission assets are located. Instead,
under the provisions of the Easement Agreement, METC pays an annual rent to Consumers Energy in
exchange for rights-of-way, leases, fee interests and licenses which allow METC to use the land on which its
transmission lines are located. Under the terms of the Easement Agreement, METC’s easement rights could be
eliminated if METC fails to meet certain requirements, such as paying contractual rent to Consumers Energy in
a timely manner. Additionally, a significant amount of the land on which our other subsidiaries’ assets are
located is subject to easements, mineral rights and other similar encumbrances. As a result, they must comply
with the provisions of various easements, mineral rights and other similar encumbrances, which may adversely
impact their ability to complete their construction projects in a timely manner.
We contract with third parties to provide services for certain aspects of our business. If any of these
agreements are terminated, we may face a shortage of labor or replacement contractors to provide the
services formerly provided by these third parties.
We enter into various agreements and arrangements with third parties to provide services for construction,
maintenance and operations of certain aspects of our business, and we utilize the services of contractors to a
significant extent. If any of these agreements or arrangements is terminated for any reason, it could result in a
shortage of a readily available workforce to provide such services and we may face difficulty finding a qualified
replacement workforce. In such a situation, if we are unable to find adequate replacements for contractors in a
timely manner, it could have an adverse effect on our results of operations and the ability to carry on our
business.
Hazards associated with high-voltage electricity transmission may result in suspension of our
operations, costly litigation or the imposition of civil or criminal penalties.
Our operations are subject to the usual hazards associated with high-voltage electricity transmission,
including explosions, fires, mechanical failure, unscheduled downtime, equipment interruptions, remediation,
chemical spills, discharges or releases of toxic or hazardous substances or gases and other environmental
risks. These hazards can cause personal injury and loss of life, severe damage to or destruction of property and
equipment and environmental damage, and may result in suspension of operations, litigation by aggrieved
parties and the imposition of civil or criminal penalties which may have a material adverse effect on our
business, financial condition and results of operations. We maintain property and casualty insurance, but 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.
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
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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 have incurred expenses in connection with environmental compliance, and we anticipate that we will
continue to do so in the future. 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.
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 acts 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 operation 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
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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 the FERC policy, failure to file jurisdictional agreements on a
timely basis may result in foregoing the time value of revenues collected under the agreement, but not to the
point where a loss would be incurred. The failure to obtain timely approval of transactions subject to FPA
Section 203, or to comply with applicable reporting, recordkeeping or accounting requirements under FPA
Section 205, could subject us to penalties that could have a material adverse effect on our financial condition,
results of operations and cash flows.
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,
such as COVID-19, or any 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. The impact of efforts to limit the spread of illness or disease on our business, financial
condition and results of operations 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.
We intend to comply with applicable obligations enacted by relevant authorities that may require broad
categories of employees and subcontractors to take actions to help prevent the spread of the respective illness
or disease, such as vaccination or testing requirements. Complying with such requirements poses the risk of
workforce disruption that could impact business continuity, including the quarantine/isolation of employees, the
possibility of resignations by unwilling employees and/or subcontractors and difficulty in satisfying future labor
needs. Significant workforce disruptions could have a material impact on our business, financial condition,
results of operations and cash flows.
The widespread outbreak of an illness or disease could disrupt the supply chains that provide services and
equipment to us as part of our capital expenditures or maintenance efforts. If our supply chains are disrupted,
we may be unable to perform necessary maintenance, which could result in increased costs as we implement
contingency plans to allow us to continue to operate. Supply chain interruptions may also increase the cost of
capital expenditures or result in the delay or cancellation of planned projects, any of which could have a material
adverse impact on our business, financial condition, results of operations and cash flows.
We require access to the capital markets to fund capital investments. If access to the capital markets is
adversely affected by any widespread illness or disease, we may need to consider alternative sources of
funding for our operations and for working capital, any of which may not be available and may increase our cost
of capital. An extended period of disruption to the economy, our workforce, supply chains or capital markets due
to the widespread outbreak of an illness or disease could materially impact our business, financial condition,
results of operations, cash flows and credit metrics.
Acts of war, terrorist attacks and other catastrophic events may have a material adverse effect on our
business, financial condition, results of operations and cash flows.
Acts of war, terrorist attacks and other catastrophic events may negatively affect our business, financial
condition and cash flows in unpredictable ways, such as increased security measures and disruptions of
markets and supply chains. Energy related assets, including, for example, our transmission facilities and DTE
Electric’s, Consumers Energy’s and IP&L’s generation and distribution facilities that we interconnect with, may
be at risk of acts of war, terrorist attacks and other catastrophic events. Such events or threats may have a
material effect on the economy in general and could result in a decline in energy consumption, which may have
a material adverse effect on our business, financial condition, results of operations and cash flows.
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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. Cyber security
incidents could harm our business by limiting our transmission capabilities, delay our development and
construction of new facilities or capital improvement projects on existing facilities or expose us to liability. Cyber-
attacks targeting our information systems could also impair our records, networks, systems and programs, or
transmit viruses to other systems. Such events or the threat of such events may increase costs associated with
heightened security requirements. In addition, if our major customers or suppliers experience a cyber-attack it
may reduce their ability to use our transmission facilities or service our transmission assets. If our business or
those of our customers and suppliers are subject to a cyber-attack, it may have a material adverse effect on our
business, financial condition, results of operations and cash flows.
Effects of climate change, including natural disasters, severe weather and other related phenomena,
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 due to climate change may negatively
affect our business and financial condition through increased costs from repairs to our transmission facilities
and implementation of contingency plans for continued operations as repairs are underway. We could also
experience disruptions to our supply chain, as our suppliers may face similar challenges to their operations from
severe weather-related events due to climate change. Furthermore, prolonged power outages to customers and
business interruptions from delays in storm restoration efforts could damage our reputation, which may have a
material adverse effect on our business, financial condition, results of operations and cash flows.
Moreover, federal, regional or state legislative or regulatory initiatives may attempt to control or limit the
causes of climate change, including greenhouse gas emissions, such as carbon dioxide and methane. Such
laws or regulations could impose costs tied to greenhouse gas emissions, operational requirements or
restrictions, or additional charges to fund energy efficiency activities. 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.
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.
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.
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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 only 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 includes 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
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
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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
commercial paper and our revolving and term loan credit agreements.
Certain provisions in our debt instruments limit our financial and operating flexibility.
Our debt instruments on a consolidated basis, including 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 2.
PROPERTIES.
Our Regulated Operating Subsidiaries’ transmission facilities are located in Michigan, Iowa, Minnesota,
Illinois, Missouri, Kansas and Oklahoma. Our MISO Regulated Operating Subsidiaries and ITC Great Plains
have agreements with other utilities for the joint ownership of specific substations, transmission lines and other
transmission assets. See Note 14 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;
• station assets, such as transformers and circuit breakers, at 684 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.
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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. Refer to Note 8 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 proceedings include certain
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 probable of loss.
Refer to Notes 5 and 16 to the consolidated financial statements for a description of certain pending legal
proceedings, which description is incorporated herein by reference.
ITEM 4. MINE SAFETY DISCLOSURES.
Not applicable.
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PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES.
ITC Holdings is a wholly-owned subsidiary of ITC Investment Holdings and ITC Holdings’ common stock is
not publicly traded.
ITC Holdings paid dividends of $273 million and $232 million to our parent, ITC Investment Holdings, during
the years ended December 31, 2022 and 2021, respectively. ITC Holdings also paid dividends of $70 million to
ITC Investment Holdings in January 2023. 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.
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, 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 currently available. Such statements 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” and similar phrases. These forward-looking
statements are based upon assumptions our management believes are reasonable. Such forward-looking
statements are based on estimates and assumptions and are subject to significant risks and uncertainties which
could cause our actual results, performance and achievements to differ materially from those expressed in, or
implied by, these statements, including, among others, the risks and uncertainties listed in this report under
“Item 1A. Risk Factors” and in our other reports filed with the SEC from time to time.
Forward-looking statements speak only as of the date made and can be affected by assumptions we might
make or by known or unknown risks and uncertainties. Many factors mentioned in our discussion in this report
will be important in determining future results. Consequently, we cannot assure you that our expectations or
forecasts expressed in such forward-looking statements will be achieved. Except as required by law, we
undertake no obligation to publicly update any of our forward-looking or other statements, whether as a result of
new information, future events or otherwise.
Statement on Prior Period Comparisons
This section of this Form 10-K generally discusses the financial condition, changes in financial condition and
results of operations for the years ended December 31, 2022 and 2021 and provides year-to-year comparisons
between the years ended December 31, 2022 and 2021. Discussions of such information for the year ended
December 31, 2020 and year-to-year comparisons between the years ended December 31, 2021 and 2020 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, 2021.
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 our economy and lifestyles become
increasingly dependent on electricity.
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Our business consists primarily of the electric transmission operations of our Regulated Operating
Subsidiaries. Through our Regulated Operating Subsidiaries, we own and operate high-voltage electric
transmission systems in Michigan’s Lower Peninsula and portions of Iowa, Minnesota, Illinois, Missouri, Kansas
and Oklahoma that transmit electricity from generating stations to local distribution facilities connected to our
transmission systems. In addition, we have electric transmission system assets under construction in
Wisconsin.
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 5 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, 2022 or that may affect future results include:
• Our capital expenditures of $933 million at our Regulated Operating Subsidiaries during the year ended
December 31, 2022, as described below under “— Capital Investment and Operating Results Trends;”
• Debt issuances, borrowings and repayments, and interest rate swaps as described in Note 8 to the
consolidated financial statements;
• The FERC orders and the D.C. Circuit Court decision related to the MISO ROE Complaints, as described
in Note 16 to the consolidated financial statements; and
• Issuance of a NOPR by the FERC on March 20, 2020, and a supplemental NOPR on April 15, 2021, that
include a proposal to update the transmission incentives policy, as described below under “ — Recent
Developments.”
These items are discussed in more detail throughout “Item 7. Management’s Discussion and Analysis of
Financial Condition and Results of Operations.”
Cost-Based Formula Rates with True-Up Mechanism
Our Regulated Operating Subsidiaries calculate their revenue requirements using cost-based Formula Rates
that are effective without the need to file rate cases with the FERC, although the rates are subject to legal
challenge at the FERC. Under their cost-based formula, each of our Regulated Operating Subsidiaries
separately calculates a revenue requirement based on financial information specific to each company. The
calculation of projected revenue requirement for a future period 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.
Under these Formula Rates, our Regulated Operating Subsidiaries recover expenses and earn an
authorized return on and recover investments in property, plant and equipment on a current basis. The Formula
Rates for a given year reflect forecasted expenses, property, plant and equipment, point-to-point revenues,
network load at our MISO Regulated Operating Subsidiaries and other items for the upcoming calendar year to
establish projected revenue requirements for each of our Regulated Operating Subsidiaries that are used as the
basis for billing 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. In the event billed revenues in a given year are more or less than actual revenue requirements,
which are calculated primarily using information from that year’s FERC Form No. 1, our Regulated Operating
Subsidiaries will refund or collect additional revenues, with interest, within a two-year period such that
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customers pay only the amounts that correspond to actual revenue requirements for that given period. This
annual true-up ensures that our Regulated Operating Subsidiaries recover their allowed costs and earn their
authorized returns.
See “Cost-Based Formula Rates with True-Up Mechanism” in Note 5 to the consolidated financial
statements for further discussion of our Formula Rates and see “Rate of Return on Equity Complaints” in Note
16 to the consolidated financial statements for detail on ROE matters.
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
1 Rate base (a)
Item
Instructions
2 Multiply by 13-month weighted average cost of capital (b)
3
Authorized return on rate base
(Line 1 x Line 2)
4 Recoverable operating expenses (including depreciation and
amortization)
5
Income taxes (c)
6 Gross revenue requirement
____________________________
(Line 3 + Line 4 + Line 5)
Amount
1,000,000
8.46 %
84,600
150,000
37,500
272,100
$
$
$
$
(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
May 2020 Order on the Initial Complaint. See Note 16 to the consolidated financial statements for detail on
ROE matters.
Debt
Equity
Percentage of
Total Capitalization
40.00%
60.00%
100.00%
Cost of Capital
5.00% =
10.77% =
Weighted
Average
Cost of
Capital
2.00 %
6.46 %
8.46 %
(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.
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.
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ITC Great Plains does not receive revenue based on a peak load or a dollar amount per kW each month.
Therefore, peak load does not have a seasonal effect on operating cash flows. The SPP tariff applicable to ITC
Great Plains is billed ratably each month based on its annual projected revenue requirement posted annually by
SPP.
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 incentive adders and
base ROE. See Note 5 and Note 16 to the consolidated financial statements for additional information related to
matters that 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 recent 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. As a result, we have increased levels of certain materials and supplies inventories
during the year ended December 31, 2022 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.
During 2021, our MISO Regulated Operating Subsidiaries filed revised depreciation rates for their assets
which were approved by the FERC in December 2021. The overall depreciation expense at our MISO
Regulated Operating Subsidiaries increased beginning on January 1, 2022. This increase is expected to result
in higher revenue from customers in the near term due to an overall increase in the rates at which we record
depreciation expense. For the year ended December 31, 2022 there was an increase in depreciation expense
of approximately $35 million resulting from our MISO Regulated Operating Subsidiaries’ new depreciation rates.
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)
interconnect new renewable generation resources; (3) upgrade physical and technological grid security to
protect critical infrastructure; and (4) expand access to electricity markets to reduce the overall cost of delivered
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energy to customers. 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)
Expenditures for property, plant and equipment (a)
____________________________
December 31, 2022
$
933 $
2023 — 2027
4,475
(a) Amounts represent the cash payments to acquire or construct property, plant and equipment, as presented
in the consolidated statements of cash flows. These amounts exclude non-cash additions to property, plant
and equipment for the AFUDC equity as well as accrued liabilities for construction, labor and materials that
have not yet been paid.
Our 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. Refer to
“Item 1. Business — Development of Business” for additional information.
During the year ended December 31, 2022, MISO advanced its long-range transmission plan, announcing
the first tranche of projects across the MISO Midwest subregion comprised of 18 transmission projects with total
associated transmission costs estimated at approximately $10 billion. The first tranche of projects was approved
by MISO’s board of directors in July 2022. Six of these projects run through our MISO Regulated Operating
Subsidiaries’ service territories, including Michigan and Iowa, where right of first refusal provisions currently
exist for incumbent transmission owners such as ITC. Other projects within this portfolio may be subject to
competitive bidding, depending on their location. Based on this preliminary information, we currently estimate
transmission investments of approximately $1.4 billion to $1.8 billion through 2030 associated with these six
projects, with approximately $700 million associated with these projects in the 2023 – 2027 capital plan.
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 queue for
generation projects and other factors beyond our control.
Recent Developments
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. We cannot predict whether these proceedings will have a material
impact, or estimate the possible impact, on our financial condition, results of operations or cash flows. See Note
16 to the consolidated financial statements for additional information on the MISO ROE Complaints.
Inflation Reduction Act of 2022
In August 2022, the President of the United States of America signed into law the Inflation Reduction Act of
2022, which enacted a number of changes to federal tax law. These changes include the introduction of a new
15% corporate minimum tax on applicable corporations, including ITC Holdings, effective for tax years
beginning after December 31, 2022. Enactment of the new law has not impacted our financial condition, results
of operations or cash flows for the year ended December 31, 2022, and at this time we do not expect a material
impact on our future results due to the implementation of the corporate minimum tax or any other aspect of the
act.
Iowa State Tax Rate Change
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.
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Adjustments to reduce the corporate income tax rate are calculated annually after the end of each fiscal year
and may continue until the rate is 5.5%.
For Iowa’s fiscal year ended June 30, 2022, net corporate income tax receipts exceeded the prescribed
threshold. On September 27, 2022, the Iowa Department of Revenue certified a reduction in the top corporate
income tax rate from 9.8% to 8.4%, effective January 1, 2023. We have revalued certain deferred tax balances
and net operating losses impacted by the change in the future Iowa corporate income tax rate. As a result,
deferred income tax expense of $7 million was recorded during the year ended December 31, 2022. In addition,
a regulatory liability of $22 million was established as of December 31, 2022 to offset deferred taxes associated
with rate base at ITC Midwest.
Incentive Adders for Transmission Rates
The FERC issued a NOPR on March 20, 2020, and a supplemental NOPR on April 15, 2021, proposing to
update its transmission incentives policy. Among other things, the rulemaking proposals would:
•
•
grant incentives to transmission projects based upon benefits to customers ensuring reliability and
reducing the cost of delivered power by reducing transmission congestion, and
eliminate the ROE adders for independent transmission ownership and for RTO participation.
The outcome of this proposal may impact the incentive adders that our Regulated Operating Subsidiaries are
authorized to apply to their base ROEs on a prospective basis. As of December 31, 2022, our MISO Regulated
Operating Subsidiaries had a total of approximately $5 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 $5 million. For ITC Great
Plains, each 10 basis point change in authorized ROE would impact annual consolidated net income by less
than $1 million.
See also the risk factor “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.”
in Item 1A. Risk Factors.
FERC NOPRs on Transmission Planning, Cost Allocation and Generator Interconnection
In response to the FERC’s July 2021 advance NOPR on transmission planning, cost allocation and
generator interconnection, multiple NOPRs were issued by the FERC during the three months ended June 30,
2022. The FERC issued a NOPR on April 21, 2022 addressing regional transmission planning and cost
allocation. The proposal requires transmission planning regions to conduct long-term, scenario-based
transmission planning and adopt enhanced transparency measures; provide a formal role for states in
developing the cost allocation for projects; and reinstate federal rights of first refusal under certain
circumstances. The FERC also issued a NOPR on June 16, 2022 proposing reforms to its generator
interconnection procedures and generator interconnection agreements to address interconnection queue
backlogs, provide certainty and prevent undue discrimination for new technologies. The time frame for
submission of comments and reply comments on these NOPRs has been completed and we are awaiting
further action from the FERC as we assess the impact of these NOPRs to our business.
Capital Structure Complaint
On May 10, 2022, the Iowa Coalition for Affordable Transmission, including IP&L, filed a complaint with the
FERC under Section 206 of the FPA. Specifically, the complaint alleged that ITC Midwest does not meet the
FERC’s three-part test for authorizing the use of a utility’s actual capital structure for ratemaking purposes which
requires that ITC Midwest 1) issue its own debt without guarantees, 2) have its own credit rating, and 3) have a
capital structure within the range of capital structures previously approved by the Commission. The Iowa
Coalition for Affordable Transmission asked the FERC to reduce ITC Midwest’s equity component from 60% to
53%. On November 2, 2022, the FERC issued an order denying the complaint. On December 2, 2022, the Iowa
Coalition for Affordable Transmission filed a request for rehearing with the FERC. As of December 31, 2022, ITC
Midwest has not recorded any liability related to the complaint.
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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. Refer below under “— Critical Accounting Policies and Estimates —
Revenue Recognition under Cost-Based Formula Rates with True-Up Mechanism” 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, including MVPs. Additionally, certain projects at ITC Great
Plains are eligible for recovery through a region-wide charge under provisions of the SPP tariff. Regional cost
sharing revenues are treated as a reduction to the net network revenue requirement under our cost-based
Formula Rates.
Point-to-Point Revenues consist of revenues generated from a type of transmission service for which the
customer pays for transmission capacity reserved along a specified path between two points on an hourly, daily,
weekly or monthly basis. Point-to-point revenues also include other components pursuant to schedules under
the MISO and SPP transmission tariffs. Point-to-point revenues are treated as a revenue credit to network or
regional customers and are a reduction to gross revenue requirement when calculating net revenue
requirement under our cost-based Formula Rates.
Scheduling, Control and Dispatch Revenues are allocated to our MISO Regulated Operating Subsidiaries
by MISO as compensation for the services performed in operating the transmission system. Such services
include monitoring of reliability data, current and next day analysis, implementation of emergency procedures
and outage coordination and switching.
Other Revenues consist of rental revenues, easement revenues, revenues relating to utilization of jointly
owned assets under our transmission ownership and operating agreements and amounts from providing
ancillary services to customers. The majority of other revenues are treated as a revenue credit and taken as a
reduction to gross revenue requirement when calculating net revenue requirement under our cost-based
Formula Rates.
Operating Expenses
Operation and Maintenance Expenses consist primarily of the costs for contractors that operate and
maintain our transmission systems as well as our personnel involved in operation and maintenance activities.
Operation expenses include activities related to control area operations, which involve balancing loads and
generation and transmission system operations activities, including monitoring the status of our transmission
lines and stations. Rental expenses relating to land easements, including METC’s Easement Agreement, are
also recorded within operation expenses.
Maintenance expenses include preventive or planned activities, such as vegetation management, tower
painting and equipment inspections, as well as reactive maintenance for equipment failures.
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General and Administrative Expenses consist primarily of costs for personnel in our legal, information
technology, finance, regulatory, human resources, community relations and communication 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 and intangible 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 and loss on extinguishment of debt 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. The interest
portion of the refunds relating to the MISO ROE Complaints is also 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.
Results of Operations
The following table summarizes historical operating results for the periods indicated:
(In millions of USD)
OPERATING REVENUES
Year Ended
December 31,
2022
2021
Increase
(Decrease)
Percentage
Increase
(Decrease)
Year Ended
December 31,
2020
Increase
(Decrease)
Percentage
Increase
(Decrease)
Transmission and other services
$
1,476 $
1,358 $
118
9 % $
1,290 $
Formula Rate true-up
Total operating revenue
OPERATING EXPENSES
Operation and maintenance
General and administrative
Depreciation and amortization
Taxes other than income taxes
Other operating (income) and
expenses, net
Total operating expenses
OPERATING INCOME
OTHER EXPENSES (INCOME)
Interest expense, net
Allowance for equity funds used during
construction
Other expenses (income), net
Total other expenses (income)
INCOME BEFORE INCOME TAXES
INCOME TAX PROVISION
(10)
1,466
(9)
1,349
107
105
295
139
(1)
645
821
269
(37)
1
233
588
146
108
128
232
133
(1)
600
749
251
(30)
(5)
216
533
127
NET INCOME
$
442 $
406 $
32
(1)
117
(1)
(23)
63
6
—
45
72
18
11 %
9 %
8
1,298
(1) %
(18) %
27 %
5 %
— %
8 %
10 %
87
115
219
124
—
545
753
7 %
240
(7)
23 %
(120) %
8 %
10 %
15 %
6
17
55
19
36
(27)
(3)
210
543
136
9 % $
407 $
68
(17)
51
21
13
13
9
(1)
55
(4)
11
(3)
(2)
6
(10)
(9)
(1)
5 %
(213) %
4 %
24 %
11 %
6 %
7 %
n/a
10 %
(1) %
5 %
11 %
67 %
3 %
(2) %
(7) %
— %
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Operating Revenues
Year ended December 31, 2022 compared to year ended December 31, 2021
The following table sets forth the components of and changes in operating revenues for the years ended
December 31, 2022 and 2021 which included revenue accruals and deferrals as described in Note 5 to the
consolidated financial statements:
(In millions of USD)
Network revenues (a)
Regional cost sharing revenues (a)
Point-to-point
Scheduling, control and dispatch (a)
Other
Total
____________________________
Percentage
2022
2021
Increase
Increase
Amount
Percentage
Amount
Percentage
(Decrease)
(Decrease)
$ 1,022
375
21
19
29
70 % $
26 %
1 %
1 %
2 %
929
358
17
19
26
69 % $
27 %
1 %
1 %
2 %
93
17
4
—
3
$ 1,466
100 % $ 1,349
100 % $
117
10 %
5 %
24 %
— %
12 %
9 %
(a) Includes a portion of the Formula Rate true-up of $(10) million and $(9) million for the years ended
December 31, 2022 and 2021, respectively.
Operating revenues increased primarily due to higher recoverable depreciation expense due to revised
depreciation rates, which became effective January 1, 2022, as well as a higher rate base associated with
higher balances of property, plant and equipment in service and resulting return.
Operating Expenses
General and administrative expenses
Year ended December 31, 2022 compared to year ended December 31, 2021
General and administrative expenses decreased due to lower compensation-related expenses, primarily due
to a decrease in share-based compensation expense.
Depreciation and amortization expenses
Year ended December 31, 2022 compared to year ended December 31, 2021
Depreciation and amortization expenses increased due to a combination of updated depreciation rates at our
MISO Regulated Operating Subsidiaries, which became effective January 1, 2022 and a higher depreciable
base resulting from property, plant and equipment in-service additions.
Other Expenses (Income)
Allowance for equity funds used during construction
Year ended December 31, 2022 compared to year ended December 31, 2021
AFUDC equity increased due primarily to higher balances of construction work in progress eligible for
AFUDC equity.
Other expenses (income), net
Year ended December 31, 2022 compared to year ended December 31, 2021
Other expenses increased primarily due to losses on certain investments associated with our supplemental
benefit plans.
Income Tax Provision
Year ended December 31, 2022 compared to year ended December 31, 2021
Our effective tax rates for the years ended December 31, 2022 and 2021 were 24.8% and 23.8%,
respectively. Our effective tax rate as of December 31, 2022 exceeded our 21% statutory federal income tax
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rate primarily due to state income taxes, including an increase in deferred income tax expense related to the
Iowa corporate income tax rate change. These increases were partially offset by AFUDC equity and the
amortization associated with excess deferred tax liabilities. The amount of income tax expense relating to
AFUDC equity and excess deferred tax was recognized as a regulatory asset and regulatory liability,
respectively, and is not included in the income tax provision. See Note 9 to the consolidated financial
statements for further discussion regarding our income tax provision.
Liquidity and Capital Resources
We expect to maintain our approach of funding our future capital requirements with cash from operations at
our Regulated Operating Subsidiaries, our existing cash and cash equivalents, future issuances under our
commercial paper program and amounts available under our revolving credit agreements (the terms of which
are described in Note 8 to the consolidated financial statements). In addition, we may from time to time secure
debt funding in the capital markets (including debt to finance or refinance portfolios of eligible projects based on
the green bond framework established by ITC Holdings), 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 commitments as described in Note 16 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 5 and 16 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. 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 us.
We expect to continue to utilize our commercial paper program and revolving credit agreements as well as
our cash and cash equivalents as needed to meet our short-term (within twelve months) cash requirements. As
of December 31, 2022, we had consolidated indebtedness under our revolving credit agreements of $208
million, with unused capacity under our revolving credit agreements of $692 million. Additionally, ITC Holdings
had $134 million of commercial paper issued and outstanding, net of discount, as of December 31, 2022, with
the ability to issue an additional $266 million under the commercial paper program. In 2022, we paid $12 million
of interest and commitment fees under our revolving credit agreements and commercial paper program.
To address our future capital requirements, we expect that we will need to obtain additional long-term debt
financing. As of December 31, 2022, 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 2023 to 2055. Total future interest payment obligations associated with these existing
fixed-rate, long-term debt obligations were $4.1 billion as of December 31, 2022, with expected interest
payment obligations of $266 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. While rising interest rates have resulted in higher coupon rates on
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recent long-term debt issuances and higher weighted average interest rates on commercial paper and
borrowings under our revolving credit agreements, the increase in interest rates has not had a material impact
on interest expense for the year ended December 31, 2022. There remains uncertainty surrounding
expectations of future interest rate fluctuations. See Note 8 to the consolidated financial statements for a
detailed discussion of our debt activity, including the commercial paper program and revolving credit
agreements, during the years ended December 31, 2022 and 2021.
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 16 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.
We have exposure to LIBOR through the revolving credit agreements of ITC Holdings and certain of our
Regulated Operating Subsidiaries. Certain tenors of LIBOR began being phased out beginning in late 2021,
with full discontinuation planned for mid-2023. We believe the rate selected as the preferred alternative to
LIBOR will be an acceptable replacement rate when LIBOR is fully discontinued and such replacement will not
have a material impact on our future liquidity and capital resources.
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. Our current credit ratings are
displayed in the following table. An explanation of these ratings may be obtained from the respective rating
agency.
ITC Holdings
Senior Unsecured Notes
Commercial Paper
ITCTransmission
First Mortgage Bonds
METC
Senior Secured Notes
ITC Midwest
First Mortgage Bonds
ITC Great Plains
First Mortgage Bonds
Covenants
S&P
Moody’s
Rating
Outlook
Rating
Outlook
BBB+
A-2
A
A
A
A
Stable
Stable
Stable
Stable
Stable
Stable
Baa2
Prime-2
A1
A1
A1
A1
Stable
Stable
Stable
Stable
Stable
Stable
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
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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, 2022, we were not in
violation of any debt covenant. In the event of a downgrade in our credit ratings, none of the covenants would
be directly impacted, although the borrowing costs under our revolving credit agreements may increase.
Cash Flows
The following table summarizes cash flows for the periods indicated:
(In millions of USD)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense
Recognition, refund and collection of revenue accruals and deferrals — including
accrued interest
Deferred income tax expense
Other
Net cash provided by operating activities
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment
Other
Net cash used in investing activities
CASH FLOWS FROM FINANCING ACTIVITIES
Net issuance of debt (including commercial paper and revolving and term loan credit
agreements)
Dividends to ITC Investment Holdings
Refundable deposits from and repayments to generators for transmission network
upgrades, net
Other
Net cash provided by financing activities
NET (DECREASE) INCREASE IN CASH, CASH EQUIVALENTS AND RESTRICTED
CASH
CASH, CASH EQUIVALENTS AND RESTRICTED CASH — Beginning of period
CASH, CASH EQUIVALENTS AND RESTRICTED CASH — End of period
$
Cash Flows From Operating Activities
Year ended December 31, 2022 compared to year ended December 31, 2021
Year Ended December 31,
2022
2021
2020
$
442 $
406 $
407
295
18
131
6
892
232
219
52
127
(32)
785
(47)
138
(85)
632
(933)
8
(925)
(834)
10
(824)
(885)
7
(878)
333
(273)
294
(232)
561
(330)
(18)
(10)
32
(21)
(1)
40
(1)
7
6 $
1
6
7 $
50
(35)
246
—
6
6
Net cash provided by operating activities was $892 million and $785 million for the years ended December
31, 2022 and 2021, respectively. The increase in cash provided by operating activities was due primarily to an
increase in cash received from operating revenues of $84 million, an increase in settlement of interest rate
swaps of $39 million and lower net payments related to the MISO ROE Complaints of $5 million, including
interest, received from customers during the year ended December 31, 2022 compared to the year ended
December 31, 2021. This increase was partially offset by an increase in payments pursuant to our long-term
incentive plans of $10 million, an increase in property tax payments of $7 million and increases in income taxes
and interest paid during the year ended December 31, 2022 compared to the year ended December 31, 2021.
Cash Flows From Investing Activities
Year ended December 31, 2022 compared to year ended December 31, 2021
Net cash used in investing activities was $925 million and $824 million for the years ended December 31,
2022 and 2021, respectively. The increase in cash used in investing activities was primarily due to an increase
in capital expenditures of $99 million during the year ended December 31, 2022 compared to the year ended
December 31, 2021.
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Cash Flows From Financing Activities
Year ended December 31, 2022 compared to year ended December 31, 2021
Net cash provided by financing activities was $32 million and $40 million for the years ended December 31,
2022 and 2021, respectively. The decrease in cash provided by financing activities was due primarily to an
increase in net repayments under our revolving credit agreements of $252 million, repayment of long-term debt
of $500 million, an increase in net repayments of commercial paper of $109 million and an increase in dividend
payments of $41 million during the year ended December 31, 2022 compared to the same period in 2021. This
decrease was partially offset by an increase in issuances of long-term debt of $900 million during the year
ended December 31, 2022 compared to the same period in 2021. See Note 8 to the consolidated financial
statements for additional discussion on debt and interest rate swaps.
Critical Accounting Policies and 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
described in Note 6 to the consolidated financial statements, we had regulatory assets and liabilities of $193
million and $698 million, respectively, as of December 31, 2022. 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 $23 million relating to
intangible assets at December 31, 2022 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
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Subsidiaries, or from differences between actual and projected monthly network peak loads at our MISO
Regulated Operating Subsidiaries.
The true-up mechanisms under our Formula Rates meet the GAAP requirements for accounting for rate-
regulated utilities and the effects of certain alternative revenue programs. Accordingly, revenue is recognized
during each reporting period based on actual revenue requirements calculated using the cost-based Formula
Rates. Our 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. The true-up amount is automatically reflected in customer bills within two years under the
provisions of the Formula Rates. See Note 6 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 2 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 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.
• Resolution or progression of existing matters through the legislative process, the courts, the FERC, the
NERC, the IRS or the Environmental Protection Agency.
Refer to Note 16 to the consolidated financial statements for discussion on the MISO ROE Complaints.
Pension and Postretirement Benefit Plan Assumptions
We sponsor certain retirement benefits for our employees, which include retirement pension plans and
certain postretirement health care, dental and life insurance benefits. Our periodic costs and obligations
associated with these plans are developed from actuarial valuations derived from a number of assumptions.
Key assumptions include:
• Discount rates used to determine obligations - Benefit obligations, service cost and interest cost are
determined by separately discounting projected benefit payments using a yield curve of high-quality
corporate bonds. As of December 31, 2022, the weighted average single equivalent discount rate for the
benefit obligation was 5.52% and 5.65% 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, 2022, we assumed that our
pension and postretirement benefit plans’ assets would generate weighted average long-term rates of
return of 5.90% and 4.50%, respectively.
• Rate of salary increases - As of December 31, 2022, we used an annual rate of salary increases of 4.00%
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, 2022.
• Rate of increase in health care costs - We used a health care cost trend rate of 6.75% for 2023 grading
down to a 5.00% ultimate rate in 2030 in valuing our postretirement benefit obligation as of December 31,
2022. These rates are based on a review of recent and expected future experience.
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The below table displays the effect on our costs and obligation of a 1% change to certain pension and
postretirement benefit plan assumptions as of December 31, 2022:
(in millions of USD)
Change to Pension Plans
Discount rate
Long-term rate of return on plan assets
Change to Postretirement Plan
Discount rate
Long-term rate of return on plan assets
Health care cost trend rate
Effect on Costs
Effect on Obligation
1% Increase
1% Decrease
1% Increase
1% Decrease
$
(1) $
(1)
(4)
(1)
5
1 $
1
(11) $
N/A
4
1
(5)
(13)
N/A
15
13
N/A
16
N/A
(12)
See Note 10 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
We have considered all new accounting pronouncements issued by the FASB and determined that it is not
likely that any of the recently issued accounting guidance will have a material impact on our consolidated
financial statements.
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 revolving credit
agreements and commercial paper, was $5,849 million and $6,995 million at December 31, 2022 and 2021,
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 revolving credit agreements and commercial paper, was
$6,649 million and $6,179 million at December 31, 2022 and 2021, respectively. An increase in interest rates of
10% (from 5.0% to 5.5%, for example) at December 31, 2022 and 2021 would decrease the fair value of debt by
$270 million and $217 million, respectively, and a decrease in interest rates of 10% at December 31, 2022 and
2021 would increase the fair value of debt by $297 million and $231 million, respectively, at that date.
Revolving Credit Agreements
At December 31, 2022 and 2021, we had a consolidated total of $208 million and $329 million, respectively,
outstanding under our revolving credit agreements, which are variable rate loans and fair value approximates
book value. A 10% increase or decrease in borrowing rates under the revolving credit agreements compared to
the weighted average rates in effect at December 31, 2022 and 2021 would increase or decrease annual
interest expense by $1 million and less than $1 million, respectively, at borrowing levels consistent with amounts
outstanding at the end of each of the respective periods.
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Commercial Paper
At December 31, 2022 and 2021, ITC Holdings had $134 million and $155 million, respectively, of
commercial paper issued and outstanding, net of discount, under the commercial paper program. Due to the
short-term nature of these financial instruments, the carrying value approximates fair value. A 10% increase or
decrease in interest rates for commercial paper compared to the weighted average interest rates in effect at
December 31, 2022 and 2021 would increase or decrease annual interest expense by $1 million and less than
$1 million, respectively, at levels consistent with amounts issued and 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, 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.
In September 2022, we terminated $450 million of 5-year interest rate swap contracts that managed interest
rate risk associated with the ITC Holdings 4.95% Senior Notes, due September 22, 2027 as described in Note 8
to the consolidated financial statements. At December 31, 2022, ITC Holdings did not have any interest rate
swaps outstanding. ITC Holdings had interest rate swaps outstanding with a total notional amount of
$375 million at December 31, 2021.
Credit Risk
Our credit risk is primarily with DTE Electric, Consumers Energy and IP&L, which were responsible for
approximately 21.0%, 24.0% and 25.4%, respectively, or $310 million, $354 million and $375 million,
respectively, of our consolidated billed revenues for the year ended December 31, 2022. This portion of total
billed revenues of DTE Electric, Consumers Energy and IP&L include the collection of 2020 revenue accruals
and deferrals and exclude any amounts for the 2022 revenue accruals and deferrals that were included in our
2022 operating revenues but will not be billed to our customers until 2024.
For the year ended December 31, 2021, our credit risk was primarily with DTE Electric, Consumers Energy
and IP&L, which were responsible for approximately 21.5%, 23.5% and 24.7%, respectively, or $300 million,
$327 million and $344 million, respectively, of our consolidated billed revenues. These percentages and
amounts of total billed revenues of DTE Electric, Consumers Energy and IP&L include the collection of 2019
revenue accruals and deferrals and exclude any amounts for the 2021 revenue accruals and deferrals that were
included in our 2021 operating revenues but will not be billed to our customers until 2023.
Refer to “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cost-
Based Formula Rates with True-Up Mechanism” for a discussion on the difference between billed revenues and
operating revenues. Under DTE Electric’s and Consumers Energy’s current rate structure, DTE Electric and
Consumers Energy include in their retail rates the actual cost of transmission services provided by
ITCTransmission and METC, respectively, in their billings to their customers, effectively passing through to end-
use consumers the total cost of transmission service. IP&L currently includes in their retail rates an allowance
for transmission services provided by ITC Midwest in their billings to their customers. However, any financial
difficulties experienced by DTE Electric, Consumers Energy or IP&L may affect their ability to make payments
for transmission service to ITCTransmission, METC, and ITC Midwest, which could negatively impact our
business. MISO, as our MISO Regulated Operating Subsidiaries’ billing agent, bills DTE Electric, Consumers
Energy, IP&L and other customers on a monthly basis and collects fees for the use of the MISO Regulated
Operating Subsidiaries’ transmission systems. SPP is the billing agent for ITC Great Plains and bills
transmission customers for the use of ITC Great Plains transmission systems. MISO and SPP have
implemented strict credit policies for its members’ customers, which include customers using our transmission
systems. Specifically, MISO and SPP require a letter of credit or cash deposit equal to the credit exposure,
which is determined by a credit scoring model and other factors, from any customer using a member’s
transmission system.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
The following financial statements and schedules are included herein:
Management’s Report on Internal Control over Financial Reporting
Report of Independent Registered Public Accounting Firm (PCAOB ID No. 34)
Consolidated Statements of Financial Position as of December 31, 2022 and 2021
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2022, 2021 and 2020
Consolidated Statements of Changes in Stockholder’s Equity for the Years Ended December 31, 2022, 2021 and
2020
Consolidated Statements of Cash Flows for the Years Ended December 31, 2022, 2021 and 2020
Notes to Consolidated Financial Statements
Schedule I — Condensed Financial Information of Registrant
Page
42
43
45
46
47
48
49
123
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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management is responsible for establishing and maintaining adequate internal control over financial
reporting. Our internal control over financial reporting is designed to provide reasonable, not absolute,
assurance as to the reliability of our financial reporting and the preparation of consolidated financial statements
in accordance with generally accepted accounting principles. Internal control over financial reporting, no matter
how well designed, has inherent limitations. Therefore, internal control over financial reporting determined to be
effective can provide only reasonable assurance with respect to financial statement preparation and may not
prevent or detect all misstatements.
Under management’s supervision, an evaluation of the design and effectiveness of our internal control over
financial reporting was conducted based on the criteria set forth in Internal Control — Integrated Framework
(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Our
assessment included documenting, evaluating and testing of the design and operating effectiveness of our
internal control over financial reporting. Based on this evaluation, management concluded that our internal
control over financial reporting was effective as of December 31, 2022.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholder of
ITC Holdings Corp.
Novi, Michigan
Opinion on the Financial Statements
We have audited the accompanying consolidated statements of financial position of ITC Holdings Corp. and
subsidiaries (the "Company") as of December 31, 2022 and 2021, 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, 2022, 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, 2022 and 2021, and the results of its operations and
its cash flows for each of the three years in the period ended December 31, 2022, 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 2, 5, 6, and
16 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
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statements applying the specialized rules to account for the effects of cost-based rate regulation. The cost-
based Formula Rates at the Company’s Regulated Operating Subsidiaries recover expenses and earn an
authorized return on and recover 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, conditions of service, accounting,
financing authorization, operating-related matters, timing of actual collection, and the return on equity.
Accounting for the economics of rate regulation impacts multiple 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 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. While the Company has indicated they expect 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 challenge at
the regulatory agency. The Company uses the formula 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 controls over the monitoring and evaluation of contingent liabilities and
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, regulatory statutes and interpretations, as well as procedural
memorandums, utility and intervener filings, legal decisions, and other publicly available information to
evaluate the likelihood of recovery in future rates or of future reduction in rates and the ability to earn a
reasonable return on equity.
•
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 9, 2023
We have served as the Company’s auditor since 2001.
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ITC HOLDINGS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
(In millions of USD, except share data)
ASSETS
Current assets
Cash and cash equivalents
Accounts receivable
Inventory
Regulatory assets
Prepaid and other current assets
Total current assets
Property, plant and equipment (net of accumulated depreciation and amortization of $2,382 and
$2,199, respectively)
Other assets
Goodwill
Regulatory assets
Other assets
Total other assets
TOTAL ASSETS
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities
Accounts payable
Accrued compensation
Accrued interest
Accrued taxes
Regulatory liabilities
Refundable deposits and advances for construction
Debt maturing within one year
Other current liabilities
Total current liabilities
Accrued pension and postretirement liabilities
Deferred income taxes
Regulatory liabilities
Refundable deposits
Other liabilities
Long-term debt
Commitments and contingent liabilities (Notes 5 and 16)
TOTAL LIABILITIES
STOCKHOLDER’S EQUITY
Common stock, without par value, 235,000,000 shares authorized, 224,203,112 shares issued and
outstanding at December 31, 2022 and 2021
Retained earnings
Accumulated other comprehensive income (loss)
Total stockholder’s equity
December 31,
2022
2021
$
4 $
139
55
12
19
229
5
128
45
21
18
217
10,637
9,961
950
181
134
1,265
12,131 $
950
190
127
1,267
11,445
112 $
127
$
$
59
69
72
22
26
384
15
759
41
1,303
676
29
44
6,607
9,459
892
1,753
27
2,672
72
56
64
14
44
654
16
1,047
52
1,161
619
28
55
6,009
8,971
892
1,584
(2)
2,474
11,445
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY
$
12,131 $
See notes to consolidated financial statements.
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ITC HOLDINGS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In millions of USD)
OPERATING REVENUES
Transmission and other services
Formula Rate true-up
Total operating revenue
OPERATING EXPENSES
Operation and maintenance
General and administrative
Depreciation and amortization
Taxes other than income taxes
Other operating (income) and expense, net
Total operating expenses
OPERATING INCOME
OTHER EXPENSES (INCOME)
Interest expense, net
Allowance for equity funds used during construction
Other expenses (income), net
Total other expenses (income)
INCOME BEFORE INCOME TAXES
INCOME TAX PROVISION
NET INCOME
OTHER COMPREHENSIVE INCOME (LOSS)
Derivative instruments, net of tax (Note 12)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Year Ended December 31,
2022
2021
2020
$
1,476 $
1,358 $
1,290
(10)
1,466
(9)
1,349
8
1,298
107
105
295
139
(1)
645
821
269
(37)
1
233
588
146
442
29
29
108
128
232
133
(1)
600
749
251
(30)
(5)
216
533
127
406
6
6
87
115
219
124
—
545
753
240
(27)
(3)
210
543
136
407
(15)
(15)
392
TOTAL COMPREHENSIVE INCOME
$
471 $
412 $
See notes to consolidated financial statements.
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ITC HOLDINGS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN
STOCKHOLDER’S EQUITY
(In millions of USD)
BALANCE, DECEMBER 31, 2019
Net income
Dividends to ITC Investment Holdings
Other comprehensive loss, net of tax (Note 12)
BALANCE, DECEMBER 31, 2020
Net income
Dividends to ITC Investment Holdings
Other comprehensive income, net of tax (Note 12)
BALANCE, DECEMBER 31, 2021
Net income
Dividends to ITC Investment Holdings
Other comprehensive income, net of tax (Note 12)
BALANCE, DECEMBER 31, 2022
Accumulated
Other
Total
Retained Comprehensive Stockholder’s
Common Stock
Earnings
Income (Loss)
Equity
$
$
$
$
892 $
1,333 $
7 $
2,232
—
—
—
407
(330)
—
—
—
(15)
407
(330)
(15)
892 $
1,410 $
(8) $
2,294
—
—
—
406
(232)
—
—
—
6
406
(232)
6
892 $
1,584 $
(2) $
2,474
—
—
—
442
(273)
—
—
—
29
442
(273)
29
892 $
1,753 $
27 $
2,672
See notes to consolidated financial statements.
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ITC HOLDINGS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions of USD)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense
Recognition, refund and collection of revenue accruals and deferrals — including accrued interest
Deferred income tax expense
Allowance for equity funds used during construction
Share-based compensation
Other
Changes in assets and liabilities, exclusive of changes shown separately:
Accounts receivable
Accounts payable
Accrued interest
Accrued compensation
Accrued taxes
Net refund settlements and adjustments related to return on equity complaints
Other current and non-current assets and liabilities, net
Net cash provided by operating activities
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment
Other
Net cash used in investing activities
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt
Borrowings under revolving credit agreements
Borrowings under term loan credit agreements
Net (repayment) issuance of commercial paper
Repayment of long-term debt
Repayments of revolving credit agreements
Repayments of term loan credit agreements
Dividends to ITC Investment Holdings
Refundable deposits from generators for transmission network upgrades
Repayment of refundable deposits from generators for transmission network upgrades
Other
Net cash provided by financing activities
NET (DECREASE) INCREASE IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH
CASH, CASH EQUIVALENTS AND RESTRICTED CASH — Beginning of period
Year Ended December 31,
2022
2021
2020
$
442 $
406 $
407
295
18
131
(37)
11
57
(8)
10
12
(15)
7
—
(31)
892
(933)
8
(925)
975
1,119
—
(21)
(500)
232
52
127
(30)
34
6
(18)
(3)
1
(3)
3
(5)
(17)
785
(834)
10
(824)
75
1,175
—
88
—
219
(47)
138
(27)
25
4
—
4
7
(14)
(3)
(65)
(16)
632
(885)
7
(878)
1,030
1,495
275
(133)
(35)
(1,240)
(1,044)
(1,596)
—
(273)
1
(19)
(10)
32
(1)
7
—
(232)
18
(39)
(1)
40
1
6
(475)
(330)
60
(10)
(35)
246
—
6
6
CASH, CASH EQUIVALENTS AND RESTRICTED CASH — End of period
$
6 $
7 $
See notes to consolidated financial statements.
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1. GENERAL
ITC HOLDINGS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 electric
transmission systems in Michigan’s Lower Peninsula and portions of Iowa, Minnesota, Illinois, Missouri, Kansas
and Oklahoma that transmit electricity from generating stations to local distribution facilities connected to our
transmission systems. In addition, we have electric transmission system assets under construction in
Wisconsin.
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
and Missouri. ITC Great Plains currently owns assets located in Kansas and Oklahoma. MISO bills and collects
revenues from the MISO Regulated Operating Subsidiaries’ customers. SPP bills and collects revenue from ITC
Great Plains’ customers.
2. 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 and Restricted Cash Equivalents — Restricted cash and restricted cash equivalents
include cash and cash equivalents that are legally or contractually restricted for use or withdrawal or are
formally set aside for a specific purpose.
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 — Depreciation and amortization expense on property, plant and
equipment was $286 million, $223 million and $209 million for the years ended December 31, 2022, 2021
and 2020, respectively.
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Property, plant and equipment in service at our Regulated Operating Subsidiaries 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 the year ended December 31, 2022, and
2.0% for the years ended December 31, 2021 and 2020. 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. 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 $9 million, $8 million and $7 million for the
years ended December 31, 2022, 2021 and 2020, respectively.
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 includes capital equipment stated at original cost consisting of items
that are expected to be used exclusively for capital projects.
Property, plant and equipment at our non-regulated 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 — Certain of our Regulated Operating Subsidiaries
have agreements with other utilities for the joint ownership of assets as described in Note 14. 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 substations and lines. 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
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is primarily recorded within operation and maintenance expenses on 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 primarily fund our two supplemental nonqualified, noncontributory retirement benefit plans for
selected management employees as described in Note 10, as well as other deferred compensation plans.
Gains and losses associated with our mutual funds as described in Note 11 are recorded in earnings.
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, 2022 and 2021, we had goodwill
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, 2022 and
determined that no impairment exists. There were no events subsequent to October 1, 2022 that
indicated impairment of our goodwill.
Deferred Financing Fees and Discount or Premium 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 or premium related to the issuance of long-term debt is recorded to long-
term debt and amortized over the life of the debt. We recorded $6 million during the year ended
December 31, 2022 and $5 million for each of the years ended December 31, 2021 and 2020 to interest
expense for the amortization of deferred financing fees and debt discounts.
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 PCBs 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
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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 $5 million as of
December 31, 2022 and $6 million as of December 31, 2021 are included in other liabilities.
Derivatives and Hedging — We may use derivative financial instruments, including interest rate swap
contracts, 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 interest rate swaps that
are designated in hedging relationships are generally classified on 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. Refer
to Note 8 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. We reverse the liabilities
recorded for those matters when a loss is no longer considered probable or the liabilities are otherwise
settled. Our liabilities exclude any estimates for legal costs not yet incurred associated with handling
these matters, which could be material. The adequacy of liabilities recorded can be significantly affected
by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters
could materially affect our consolidated financial statements.
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 on 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 on 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. Refer to Note 5 under “Cost-Based Formula Rates
with True-Up Mechanism” and Note 3 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. Generally, 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 settled only in cash. However, certain SBUs granted to the
executives may settle 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 subsequent quarter. However, certain awards may vest over a shorter period or
on the grant date if certain retirement eligibility criteria are met. The PBUs and SBUs earn dividend
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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.
Refer to Note 13 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 our interest rate swaps.
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 in our
consolidated statements of financial position.
The accounting standards for uncertainty in income taxes prescribe a recognition threshold and a
measurement attribute for tax positions taken, or expected to be taken, in a tax return that may not be
sustainable. As of December 31, 2022, 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 2018 and earlier. State and city jurisdictions that remain subject to examination
range from tax years 2018 to 2021. In the event we are assessed interest or penalties by any income tax
jurisdictions, interest and penalties would be recorded as interest expense and other expense,
respectively, in our consolidated statements of comprehensive income. Refer to Notes 6 and 9 for
additional discussion on income taxes.
3. REVENUE
Our total revenues are comprised of revenues which arise from three classifications including transmission
services, other services, and Formula Rate true-up. As other services revenue is immaterial, it is presented in
combination with transmission services on the consolidated statements of comprehensive income.
Transmission Services
transmission systems. As
Through our Regulated Operating Subsidiaries, we generate nearly all our revenue from providing electric
transmission services over our
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.
independent
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
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fluctuations of actual load, the unbilled revenue amount generally increases during the spring and summer and
decreases during the fall and winter. See Note 4 for information on changes in unbilled accounts receivable.
Other Services
Other services revenue consists of rental revenues, easement revenues, and amounts from providing
ancillary services. A portion of other services revenue is treated as a revenue credit and reduces gross revenue
requirement when calculating net revenue requirement under our Formula Rates. Total other services revenue
was $6 million for each of the years ended December 31, 2022 and 2021 and $5 million for the year ended
December 31, 2020.
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 “Cost-Based Formula Rates with True-Up Mechanism” in Note 5 for more information on our
Formula Rates.
4. ACCOUNTS RECEIVABLE
The following table presents the components of accounts receivable on the consolidated statements of
financial position:
(In millions of USD)
Trade accounts receivable
Unbilled accounts receivable
Other (a)
Total accounts receivable
____________________________
December 31,
2022
2021
2020
2019
$
2 $
3 $
2 $
124
13
$
139 $
116
9
128 $
102
10
114 $
2
102
13
117
(a) Includes amounts due from affiliates, see “Related Party Receivables and Payables” in Note 15 for
additional information.
5. REGULATORY MATTERS
Cost-Based Formula Rates with True-Up Mechanism
The transmission revenue requirements at our Regulated Operating Subsidiaries are set annually using
Formula Rates 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 “Rate of Return on Equity Complaints” in
Note 16 for detail on ROE matters for our MISO Regulated Operating Subsidiaries and "ROE and Incentive
Adders for Transmission Rates" and “Capital Structure Complaint” discussed herein.
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
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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.
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, 2022:
(In millions of USD)
Net regulatory liabilities as of December 31, 2021
Net collection of 2020 revenue deferrals and accruals, including accrued interest
Net revenue deferral, including accrued interest
Net accrued interest payable
Net regulatory liabilities as of December 31, 2022
Total
$
(2)
(8)
(9)
(1)
$
(20)
Regulatory assets and liabilities associated with our Regulated Operating Subsidiaries’ Formula Rate
revenue accruals and deferrals, including accrued interest, are recorded in the consolidated statements of
financial position as follows:
(In millions of USD)
Current regulatory assets
Non-current regulatory assets
Current regulatory liabilities
Non-current regulatory liabilities
Net regulatory liabilities
December 31,
2022
2021
$
12 $
29
(22)
(39)
$
(20) $
20
10
(13)
(19)
(2)
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. As of December 31, 2022, 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
For each of the years ended December 31, 2022, 2021 and 2020, the authorized ROE used by the MISO
Regulated Operating Subsidiaries was 10.77% and is 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. See “Rate of
Return on Equity Complaints” in Note 16 for a discussion of the MISO ROE Complaints.
ITC Great Plains
On July 16, 2020, in response to a complaint filed by the KCC under section 206 of the FPA, the FERC
issued an order revising the adder for independent transmission ownership for ITC Great Plains from 100 basis
points to 25 basis points, and requiring ITC Great Plains to include the revised adder, effective June 11, 2019, in
their Formula Rate. In addition, the order directed ITC Great Plains to provide refunds, with interest, for the
period from June 11, 2019 through July 16, 2020. During the fourth quarter of 2020, refunds of $4 million were
made to settle the refund liability.
Prior to the issuance of the FERC order on July 16, 2020, the authorized ROE used by ITC Great Plains was
12.16% and was composed of a base ROE of 10.66% with a 100 basis point adder for independent
transmission ownership and a 50 basis point adder for RTO participation. Since the July 16, 2020 order, the
authorized ROE used by ITC Great Plains has been 11.41% and is composed of a base ROE of 10.66% with a
25 basis point adder for independent transmission ownership and a 50 basis point adder for RTO participation.
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Capital Structure Complaint
On May 10, 2022, the Iowa Coalition for Affordable Transmission, including IP&L, filed a complaint with the
FERC under Section 206 of the FPA. Specifically, the complaint alleged that ITC Midwest does not meet the
FERC’s three-part test for authorizing the use of a utility’s actual capital structure for ratemaking purposes which
requires that ITC Midwest 1) issue its own debt without guarantees, 2) have its own credit rating, and 3) have a
capital structure within the range of capital structures previously approved by the Commission. The Iowa
Coalition for Affordable Transmission asked the FERC to reduce ITC Midwest’s equity component from 60% to
53%. On November 2, 2022, the FERC issued an order denying the complaint. On December 2, 2022, the Iowa
Coalition for Affordable Transmission filed a request for rehearing with the FERC. As of December 31, 2022, ITC
Midwest has not recorded any liability related to the complaint.
Depreciation Rate Filings
During 2021, our MISO Regulated Operating Subsidiaries filed revised depreciation rates for their assets
which were approved by the FERC in December 2021. The overall depreciation expense at our MISO
Regulated Operating Subsidiaries increased beginning on January 1, 2022, which will result in higher revenue
as the increase in depreciation expense flows through to customer bills.
56
December 31,
2022
2021
12 $
—
12
29
121
8
1
22
181
$
193 $
20
1
21
10
114
20
16
30
190
211
13
1
14
19
31
70
495
4
619
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6. REGULATORY ASSETS AND LIABILITIES
The following table summarizes the regulatory asset and liability balances:
(In millions of USD)
Regulatory Assets:
Current:
Revenue accruals (including accrued interest of less than $1 as of December 31,
2022 and 2021) (a)
Other
$
Total current
Non-current:
Revenue accruals (including accrued interest of less than $1 as of December 31,
2022 and 2021) (a)
Income taxes recoverable related to AFUDC equity
Pensions and postretirement
Accrued asset removal costs
Other
Total non-current
Total Regulatory Assets
Regulatory Liabilities:
Current:
Revenue deferrals (including accrued interest of $1 as of December 31, 2022 and
2021) (a)
$
22 $
Other
Total current
Non-current:
Revenue deferrals (including accrued interest of $1 and less than $1 as of
December 31, 2022 and 2021, respectively) (a)
Pensions and postretirement
Accrued asset removal costs
Income taxes refundable due to change in federal income tax rate
Other
Total non-current
Total Regulatory Liabilities
____________________________
—
22
39
52
80
480
25
676
$
698 $
(a) Refer to discussion of revenue accruals and deferrals in Note 5 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.
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
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consistent with the depreciation of the AFUDC equity that has been capitalized to property, plant and
equipment.
Pensions and Postretirement
Accounting standards for defined benefit pension and other postretirement plans for rate-regulated entities
allow for amounts that otherwise would have been recorded to AOCI to be recorded as regulatory assets or
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 or reductions to the related regulatory asset. Removal costs
incurred increase the related regulatory asset or reduce the related regulatory liability. Our Regulated Operating
Subsidiaries include these regulatory assets and liabilities as reductions or increases, respectively, to
accumulated depreciation for rate-making purposes when determining rate base.
Income Taxes Refundable Due to Change in Federal Income Tax Rate
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 the years ended December
31, 2022 and 2021, we recorded $9 million and $8 million, respectively, of amortization related to the excess
deferred taxes. The net regulatory liability is included within deferred taxes for rate-making purposes when
determining rate base.
7. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment — net consisted of the following:
(In millions of USD)
Property, plant and equipment
Regulated Operating Subsidiaries:
Property, plant and equipment in service
Construction work in progress
Capital equipment
Other
ITC Holdings and other
Total
Less: Accumulated depreciation and amortization
Property, plant and equipment, net
December 31,
2022
2021
$
$
12,039 $
748
127
91
14
13,019
(2,382)
10,637 $
11,434
529
96
87
14
12,160
(2,199)
9,961
Additions to property, plant and equipment in-service and construction work in progress during 2022 and
2021 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 such as our MVPs.
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8. DEBT
Amounts of outstanding debt were classified as debt maturing within one year and long-term debt in the
consolidated statements of financial position as follows:
(In millions of USD)
December 31,
2022
2021
ITC Holdings 6.375% Senior Notes, due September 30, 2036
ITC Holdings 4.05% Senior Notes, due July 1, 2023 (a)
ITC Holdings 3.65% Senior Notes, due June 15, 2024
ITC Holdings 5.30% Senior Notes, due July 1, 2043
ITC Holdings 3.25% Notes, due June 30, 2026
ITC Holdings 2.70% Senior Notes, due November 15, 2022 (a)
ITC Holdings 3.35% Senior Notes, due November 15, 2027
ITC Holdings 2.95% Senior Notes, due May 14, 2030
ITC Holdings 4.95% Senior Notes, due September 22, 2027
ITC Holdings Revolving Credit Agreement, due October 18, 2024
ITC Holdings Commercial Paper Program (a)
ITCTransmission 6.125% First Mortgage Bonds, Series C, due March 31, 2036
ITCTransmission 4.625% First Mortgage Bonds, Series E, due August 15, 2043
ITCTransmission 4.27% First Mortgage Bonds, Series F, due June 10, 2044
ITCTransmission 4.00% First Mortgage Bonds, Series G, due March 30, 2053
ITCTransmission 3.30% First Mortgage Bonds, Series H, due August 28, 2049
ITCTransmission 2.93% First Mortgage Bonds, Series I, due January 14, 2052
ITCTransmission 2.93% First Mortgage Bonds, Series J, due January 14, 2052
ITCTransmission Revolving Credit Agreement, due October 18, 2024
METC 5.64% Senior Secured Notes, due May 6, 2040
METC 3.98% Senior Secured Notes, due October 26, 2042
METC 4.19% Senior Secured Notes, due December 15, 2044
METC 3.90% Senior Secured Notes, due April 26, 2046
METC 4.55% Senior Secured Notes, due January 15, 2049
METC 4.65% Senior Secured Notes, due July 10, 2049
METC 2.90% Senior Secured Notes, Series A, due August 3, 2051
METC 3.02% Senior Secured Notes, due October 14, 2055
METC 3.05% Senior Secured Notes, Series B, due May 10, 2052
METC Revolving Credit Agreement, due October 18, 2024
ITC Midwest 6.15% First Mortgage Bonds, Series A, due January 31, 2038
ITC Midwest 4.60% First Mortgage Bonds, Series D, due December 17, 2024
ITC Midwest 3.50% First Mortgage Bonds, Series E, due January 19, 2027
ITC Midwest 4.09% First Mortgage Bonds, Series F, due April 30, 2043
ITC Midwest 3.83% First Mortgage Bonds, Series G, due April 7, 2055
ITC Midwest 4.16% First Mortgage Bonds, Series H, due April 18, 2047
ITC Midwest 4.32% First Mortgage Bonds, Series I, due November 1, 2051
ITC Midwest 3.13% First Mortgage Bonds, Series J, due July 15, 2051
ITC Midwest 3.87% First Mortgage Bonds, Series K, due October 12, 2027
ITC Midwest 4.53% First Mortgage Bonds, Series L, due October 12, 2052
ITC Midwest Revolving Credit Agreement, due October 18, 2024
ITC Great Plains 4.16% First Mortgage Bonds, Series A, due November 26, 2044
ITC Great Plains Revolving Credit Agreement, due October 18, 2024
Other
Total principal
Unamortized deferred financing fees and discount
Total debt
____________________________
$
$
200 $
250
400
300
400
—
500
700
600
10
134
100
285
100
225
75
20
130
61
50
75
150
200
50
50
75
150
75
36
175
75
100
100
225
200
175
180
75
75
78
150
23
3
7,035
(44)
6,991 $
200
250
400
300
400
500
500
700
—
39
155
100
285
100
225
75
—
—
88
50
75
150
200
50
50
75
150
—
30
175
75
100
100
225
200
175
180
—
—
139
150
33
3
6,702
(39)
6,663
(a) As of December 31, 2022 and 2021 there was $384 million and $654 million, respectively, net of
unamortized deferred financing fees and discount, of debt included within debt maturing within one year in
the consolidated statements of financial position.
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The annual maturities of debt as of December 31, 2022 are as follows:
(In millions of USD)
2023
2024
2025
2026
2027
2028 and thereafter
Total
ITC Holdings
Senior Unsecured Notes
$
$
384
683
—
400
1,275
4,293
7,035
On September 22, 2022, ITC Holdings completed the private offering of $600 million aggregate principal
amount of unsecured 4.95% Senior Notes, due September 22, 2027. The Senior Notes are redeemable prior to
August 22, 2027, 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
repay the $500 million aggregate principal amount of ITC Holdings 2.70% Senior Notes due November 15,
2022, to repay $89 million under ITC Holdings’ commercial paper program and for general corporate purposes.
The Senior Notes were issued under ITC Holdings’ indenture, dated April 18, 2013, as supplemented from time
to time, including by the Sixth Supplemental Indenture, dated as of September 22, 2022.
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,
2022, ITC Holdings had $134 million of commercial paper, net of discount, issued and outstanding under the
program, with a weighted average interest rate of 4.67% and weighted average remaining days to maturity of 11
days. The amount outstanding as of December 31, 2022 was classified as debt maturing within one year in the
consolidated statements of financial position. As of December 31, 2021, ITC Holdings had $155 million of
commercial paper issued and outstanding.
ITCTransmission
First Mortgage Bonds
On January 14, 2022, ITCTransmission issued $130 million of aggregate principal amount of 2.93% First
Mortgage Bonds, Series J due January 14, 2052. The proceeds were used to repay existing indebtedness
under the revolving credit agreement and intercompany loan agreement, to partially fund capital expenditures
and for general corporate purposes. ITCTransmission also issued an additional $20 million of aggregate
principal amount of 2.93% First Mortgage Bonds, Series I due January 14, 2052. The proceeds from the First
Mortgage Bonds, Series I were used to fund or refinance a portfolio of eligible renewable energy projects based
on the green bond framework established by ITC Holdings. 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 May 10, 2022, METC issued $75 million of 3.05% Series B Senior Secured Notes due May 10, 2052. The
proceeds from the Series B Senior Secured Notes were used to repay borrowings under the METC 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.
On August 3, 2021, METC issued $75 million of 2.90% Series A Senior Secured Notes, due August 3, 2051.
The proceeds from the Series A Senior Secured Notes were used to fund or refinance a portfolio of eligible
renewable energy projects based on the green bond framework established by ITC Holdings. All of METC’s
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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 October 12, 2022, ITC Midwest issued an aggregate of $75 million of 3.87% First Mortgage Bonds Series
K, due October 12, 2027 and an aggregate of $75 million of 4.53% First Mortgage Bonds Series L, due October
12, 2052. The proceeds are expected to fund or refinance a portfolio of eligible renewable energy projects
based on the green bond framework established by ITC Holdings. 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.
Derivative Instruments and Hedging Activities
In September 2022, we terminated $450 million of 5-year interest rate swap contracts that managed interest
rate risk associated with the ITC Holdings 4.95% Senior Notes, due September 22, 2027. A summary of the
terminated interest rate swaps is provided below:
(In millions of USD,
except percentages)
5-year interest
rate swaps
5-year interest
rate swaps
Total
Notional
Amount
Weighted Average
Fixed Rate of
Interest Rate Swaps
Comparable
Reference Rate of
Notes
Benchmark
Rate
Gain on
Derivatives
$
375
1.471%
3.441%
LIBOR
$
75
450
$
1.540%
3.162%
SOFR
$
33
6
39
Settlement Date
September
2022
September
2022
The interest rate swaps qualified for cash flow hedge accounting treatment, and the cumulative pre-tax gain
of $39 million was recorded net of tax in AOCI. This amount is being amortized as a component of interest
expense over the term of the related debt. The swap settlement payment was recognized within cash flows from
operating activities in the consolidated statements of cash flows. At December 31, 2022, ITC Holdings did not
have any interest rate swaps outstanding. ITC Holdings had interest rate swaps outstanding with a total notional
amount of $375 million at December 31, 2021.
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Revolving Credit Agreements
At December 31, 2022, ITC Holdings and certain of its Regulated Operating Subsidiaries had the following
unsecured revolving credit facilities available:
(In millions of USD, except percentages)
ITC Holdings
ITCTransmission
METC
ITC Midwest
ITC Great Plains
Total
____________________________
Total
Available
Capacity
Outstanding
Balance (a)
Unused
Capacity
$
400 $
10 $
390 (d)
100
100
225
75
61
36
78
23
$
900 $
208 $
39
64
147
52
692
Weighted
Average
Interest Rate on
Outstanding
Balance (b)
5.69%
5.44%
5.44%
5.44%
5.44%
Commitment
Fee Rate (c)
0.175 %
0.10 %
0.10 %
0.10 %
0.10 %
(a) Included within long-term debt in the consolidated statements of financial position.
(b) Interest charged on borrowings depends on the variable rate structure we elected at the time of each
borrowing.
(c) Calculation based on the average daily unused commitments, subject to adjustment based on the
borrower’s credit rating.
(d) ITC Holdings’ revolving credit agreement may be used for general corporate purposes, including to repay
commercial paper issued pursuant to the commercial paper program described above, if necessary. While
outstanding commercial paper does not reduce available capacity under ITC Holdings’ revolving credit
agreement, the unused capacity under this agreement adjusted for the commercial paper outstanding was
$256 million as of December 31, 2022.
9.
INCOME TAXES
For the years ended December 31, 2022, 2021 and 2020, our effective tax rates were 24.8%, 23.8% and
25.0%, 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:
(In millions of USD)
Year Ended December 31,
2022
2021
2020
Income tax expense at 21% federal statutory rate
$
123 $
112 $
State income taxes (net of federal benefit) (a)
AFUDC equity
Amortization of revalued deferred federal income taxes
Valuation allowance
Other, net
Total income tax provision
36
(6)
(9)
1
1
24
(5)
(9)
4
1
114
28
(4)
(2)
—
—
$
146 $
127 $
136
____________________________
(a) Amount for the year ended December 31, 2022 includes the impact of the remeasurement of certain
deferred tax balances and NOLs for Iowa due to the corporate tax rate change discussed herein.
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Components of the income tax provision were as follows:
(In millions of USD)
Current income tax expense (benefit)
Deferred income tax expense
Total income tax provision
Year Ended December 31,
2022
2021
2020
$
$
15 $
— $
131
127
146 $
127 $
(2)
138
136
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.
Adjustments to reduce the corporate income tax rate are calculated annually after the end of each fiscal year
and may continue until the rate is 5.5%.
For Iowa’s fiscal year ended June 30, 2022, net corporate income tax receipts exceeded the prescribed
threshold. On September 27, 2022, the Iowa Department of Revenue certified a reduction in the top corporate
income tax rate from 9.8% to 8.4%, effective January 1, 2023. We have revalued certain deferred tax balances
and net operating losses impacted by the change in the future Iowa corporate income tax rate. As a result,
deferred income tax expense of $7 million was recorded during the year ended December 31, 2022. In addition,
a regulatory liability of $22 million was established as of December 31, 2022 to offset deferred taxes associated
with rate base at ITC Midwest.
Deferred income tax assets (liabilities) consisted of the following:
(In millions of USD)
Property, plant and equipment
Federal income tax NOLs and other credits
Goodwill
Regulatory liability gross up due to change in federal income tax rate
Pension and postretirement liabilities
State income tax NOLs (net of federal benefit)
Valuation allowance
Other, net
Net deferred tax liabilities
Gross deferred income tax liabilities
Gross deferred income tax assets
Valuation allowance
Net deferred tax liabilities
December 31,
2022
2021
$
(1,363) $
(1,274)
5
(148)
125
24
47
(5)
12
49
(145)
131
22
57
(4)
3
$
$
(1,303) $
(1,161)
(1,542) $
(1,434)
244
(5)
277
(4)
$
(1,303) $
(1,161)
We had federal income tax NOLs as of December 31, 2022. We expect to use our NOLs prior to their
expirations. We also had state income tax NOLs as of December 31, 2022. While 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.
10. RETIREMENT BENEFITS AND ASSETS HELD IN TRUST
Pension and Postretirement Plan Benefits
We have a qualified defined benefit pension plan (“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
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of the plan, and other considerations as we deem appropriate. We made contributions to the retirement plan of
$3 million in 2022 and $4 million in each of 2021 and 2020. We do not expect to contribute to the retirement
plan in 2023.
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 $47 million and
$54 million at December 31, 2022 and 2021, 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.
For the year ended December 31, 2022, we did not contribute to the supplemental benefit plans. For each of the
years ended December 31, 2021 and 2020, we contributed $3 million to these supplemental benefit plans.
We provide certain postretirement health care, dental, and life insurance benefits for eligible employees (the
“postretirement benefit plan”). We contributed $7 million, $8 million, and $10 million to the postretirement benefit
plan in 2022, 2021, and 2020, respectively. We expect to contribute $2 million to the postretirement benefit plan
in 2023.
Net periodic benefit costs by component for the pension plans and postretirement benefit plan were as
follows:
Pension Plans
Year Ended December 31,
Postretirement Benefit Plan
Year Ended December 31,
(In millions of USD)
2022
2021
2020
2022
2021
2020
Service cost
Interest cost
Expected return on plan assets
Amortization of unrecognized
loss/(gain)
Net benefit cost
$
$
8 $
4
(7)
1
6 $
9 $
3
(6)
1
7 $
8 $
12 $
11 $
4
(6)
1
7 $
4
(7)
(2)
7 $
3
(6)
—
8 $
11
4
(5)
—
10
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The following table reconciles the obligations, assets, and funded status of the pension plans and
postretirement benefit plan as well as the presentation of the funded status of the plans in the consolidated
statements of financial position:
(In millions of USD)
Change in Benefit Obligation:
Beginning projected benefit obligation /
accumulated postretirement benefit obligation
Service cost
Interest cost
Plan amendments
Actuarial net gain
Benefits paid
Settlements
Pension Plans
December 31,
Postretirement Benefit Plan
December 31,
2022
2021
2022
2021
$
(160) $
(162) $
(127) $
(8)
(4)
—
41
7
—
(9)
(3)
—
5
7
2
(12)
(4)
—
51
2
—
(122)
(11)
(3)
—
8
1
—
Ending projected benefit obligation / accumulated
postretirement benefit obligation
(124)
(160)
(90)
(127)
Change in Plan Assets:
Beginning plan assets at fair value
Actual return on plan assets
Employer contributions
Benefits paid
Ending plan assets at fair value
Funded status, (underfunded)/overfunded
Accumulated benefit obligation:
Retirement plan
Supplemental benefit plans
Total accumulated benefit obligation
Amounts recorded as:
Funded Status:
117
(20)
3
(4)
96
107
10
4
(4)
117
140
(23)
7
(2)
122
(28) $
(43) $
32 $
(76) $
(44)
(120) $
(99)
(54)
(153)
N/A
N/A
N/A
$
$
$
Accrued pension and postretirement liabilities
$
(41) $
(52) $
— $
Other non-current assets
Other current liabilities
Total
Unrecognized Amounts in Non-Current
Regulatory Assets:
Net actuarial loss
Net prior service cost
Total
Unrecognized Amounts in Non-Current
Regulatory Liabilities:
Net actuarial (gain)
Net prior service cost/(credit)
Total
17
(4)
13
(4)
32
—
(28) $
(43) $
32 $
8 $
—
8 $
(3) $
1
(2) $
19 $
1
20 $
— $
—
— $
— $
—
— $
(49) $
(1)
(50) $
$
$
$
$
$
120
13
8
(1)
140
13
N/A
N/A
N/A
—
13
—
13
—
—
—
(29)
(2)
(31)
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 6. The amounts recorded as a
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regulatory asset or regulatory liability represent a net periodic benefit cost or credit to be recognized in our
operating income in future periods. Our measurement of the accumulated benefit obligation for the
postretirement benefit plan as of December 31, 2022 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. This resulted in a reduction in the accumulated postretirement benefit obligation of $7 million as of
December 31, 2022 related to benefits attributed to past services. Our measurement of the accumulated benefit
obligation for the postretirement benefit plan as of December 31, 2021 does not reflect the potential receipt of
any prescription drug subsidies.
The net actuarial gains for the year ended December 31, 2022 within the change in benefit obligation for
both the pension plans and postretirement benefit plan are primarily the result of increases in the discount rates.
The net actuarial gains for the year ended December 31, 2021 within the change in benefit obligation for
both the pension plans and postretirement benefit plan are primarily the result of increases in the discount rates
and actual returns on plan assets greater than expected.
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:
(In millions of USD)
Projected benefit obligation
Fair value of plan assets (a)
____________________________
Pension Plans
December 31,
2022
2021
$
(45) $
—
(56)
—
(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:
(In millions of USD)
Accumulated benefit obligation
Fair value of plan assets (a)
____________________________
Pension Plans
December 31,
2022
2021
$
(44) $
—
(54)
—
(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 benefit obligations for the pension plans and postretirement
benefit plan are as follows:
Weighted average discount rate
Weighted average interest crediting rate
Annual rate of salary increases
Health care cost trend rate
Ultimate health care cost trend rate
Year that the ultimate trend rate is reached
Annual rate of increase in dental benefit costs
Pension Plans
December 31,
2022
5.52%
4.00%
4.00%
N/A
N/A
N/A
N/A
2021
2.86%
4.00%
4.00%
N/A
N/A
N/A
N/A
2020
2.49%
4.00%
4.00%
N/A
N/A
N/A
N/A
Postretirement Benefit Plan
December 31,
2022
2021
2020
5.65%
3.14%
2.94%
N/A
4.00%
6.75%
5.00%
2030
N/A
4.00%
5.75%
5.00%
2025
N/A
4.00%
6.00%
5.00%
2025
4.50%
4.50%
4.50%
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Actuarial assumptions used to determine the benefit cost for the pension plans and postretirement benefit
plan are as follows:
Pension Plans
Postretirement Benefit Plan
Year Ended December 31,
Year Ended December 31,
2022
2021
2020
2022
2021
2020
Weighted average discount rate — service
cost
Weighted average discount rate — interest
cost
Weighted average interest crediting rate
Annual rate of salary increases
Health care cost trend rate
Ultimate health care cost trend rate
Year that the ultimate trend rate is reached
Expected long-term rate of return on plan
assets
3.05%
2.77%
3.47%
3.32%
3.20%
3.80%
2.44%
4.00%
4.00%
N/A
N/A
N/A
1.93%
4.00%
4.00%
N/A
N/A
N/A
2.91%
4.00%
4.00%
N/A
N/A
N/A
2.87%
2.50%
3.30%
N/A
4.00%
5.75%
5.00%
2025
N/A
4.00%
6.00%
5.00%
2025
N/A
4.00%
6.25%
5.00%
2025
5.90%
5.70%
6.00%
4.50%
4.30%
4.50%
At December 31, 2022, 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)
2023
2024
2025
2026
2027
2028 through 2032
Pension Plans
$
9 $
9
10
10
10
67
Postretirement
Benefit Plan
2
2
3
3
3
25
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, 2022 and 2021, the plan assets of the retirement plan and postretirement benefit plan
consisted of the following assets by category:
Asset Category
Fixed income securities
Equity securities
Total
Target Allocation
Pension Plans
Postretirement Benefit Plan
2022
2022
2021
2022
2021
50 %
50 %
100 %
50 %
50 %
100 %
50 %
50 %
100 %
50 %
50 %
100 %
50 %
50 %
100 %
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We determine our expected long-term rate of return on plan assets based on the current and expected target
allocations of the retirement plan and postretirement benefit plan investments and considering historical and
expected long-term rates of return on comparable fixed income investments and equity investments.
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, 2022 and 2021, there were no transfers between levels.
For the years ended December 31, 2022 and 2021, the fair value of retirement plan and postretirement
benefit plan assets measured on a recurring basis at the Level 1 tier were as follows:
(In millions of USD)
Mutual funds — U.S. equity securities
Mutual funds — international equity securities
Mutual funds — fixed income securities
Total
Pension Plans
December 31,
Postretirement Benefit Plan
December 31,
2022
2021
2022
2021
$
$
38 $
10
48
96 $
47 $
12
58
59 $
3
61
117 $
123 $
67
3
70
140
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 the year
ended December 31, 2022 and $6 million for each of the years ended December 31, 2021 and 2020.
11. 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, 2022 and 2021, there were no transfers between levels.
Our assets measured at fair value subject to the three-tier hierarchy at December 31, 2022, were as follows:
(In millions of USD)
Financial assets measured on a recurring basis:
Mutual funds — fixed income securities
Mutual funds — equity securities
Total
Fair Value Measurements at Reporting Date Using
Quoted Prices in
Active Markets
for
Identical Assets
(Level 1)
Significant
Other
Observable
Inputs
(Level 2)
Significant
Unobservable
Inputs
(Level 3)
$
$
44 $
11
55 $
— $
—
— $
—
—
—
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Our assets measured at fair value subject to the three-tier hierarchy at December 31, 2021, were as follows:
(In millions of USD)
Financial assets measured on a recurring basis:
Mutual funds — fixed income securities
Mutual funds — equity securities
Interest rate swap derivatives
Total
Fair Value Measurements at Reporting Date Using
Quoted Prices in
Active Markets
for
Identical Assets
(Level 1)
Significant
Other
Observable
Inputs
(Level 2)
Significant
Unobservable
Inputs
(Level 3)
$
$
51 $
12
—
63 $
— $
—
2
2 $
—
—
—
—
As of December 31, 2022 and 2021, 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 10. 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 income and expense.
As of December 31, 2021, the assets related to derivatives consist of interest rate swaps as discussed in
Note 8. The fair value of our interest rate swap derivatives is determined based on a DCF method using
benchmark interest rates of LIBOR or SOFR 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, 2022 and 2021.
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 revolving credit agreements and commercial paper, was $5,849
million and $6,995 million at December 31, 2022 and 2021, 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 revolving credit
agreements and commercial paper, was $6,649 million and $6,179 million at December 31, 2022 and 2021,
respectively.
Revolving Credit Agreements
At December 31, 2022 and 2021, we had a consolidated total of $208 million and $329 million, respectively,
outstanding under our revolving credit agreements, which are variable rate loans. The fair value of these loans
approximates book value based on the borrowing rates currently available for variable rate loans 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 and current liabilities, including
cash and cash equivalents, special deposits and commercial paper, approximates their fair value due to the
short-term nature of these instruments.
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12. STOCKHOLDER'S EQUITY
Accumulated Other Comprehensive Income (Loss)
The following table provides the components of changes in AOCI:
(In millions of USD)
Balance at the beginning of period
Derivative Instruments
Year Ended December 31,
2022
2021
2020
$
(2) $
(8) $
7
Reclassification of net loss relating to interest rate cash flow hedges
from AOCI to earnings (net of tax of $1 for the year ended December
31, 2022, $2 for the year ended December 31, 2021 and $1 for the year
ended December 31, 2020) (a)
Gain (loss) on interest rate swaps relating to interest rate cash flow
hedges (net of tax of $11 for the year ended December 31, 2022, $1 for
the year ended December 31, 2021 and $8 for the year ended
December 31, 2020)
Total other comprehensive income (loss), net of tax
Balance at the end of period
____________________________
3
26
29
27 $
4
2
6
(2) $
3
(18)
(15)
(8)
$
(a) The reclassification of the net loss relating to interest rate cash flow hedges is reported in interest expense
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, 2023 is expected to be approximately $1 million (net of tax of less
than $1 million). The reclassification is reported in interest expense on a pre-tax basis.
13. SHARE-BASED COMPENSATION AND EMPLOYEE SHARE PURCHASE PLAN
We recorded share-based compensation costs as follows:
(In millions of USD)
Operation and maintenance expenses
General and administrative expenses
Amounts capitalized to property, plant and equipment
Total share-based compensation costs
Total tax benefit recognized in the consolidated statements of
comprehensive income
Year Ended December 31,
2022
2021
2020
$
$
$
2 $
2 $
9
8
32
9
19 $
43 $
5 $
9 $
2
23
7
32
8
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
which are also re-measured consistent with the target award and settled in cash at the end of the vesting
period.
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The following table shows the changes in PBUs during the year ended December 31, 2022:
PBUs at December 31, 2021
Granted
Vested and paid out
Forfeited
PBUs at December 31, 2022
Number of
Performance
Based Units
899,092
283,063
(336,368)
(26,396)
819,391
The following table presents the classification in the consolidated statements of financial position of
obligations related to outstanding PBUs not yet settled:
(In millions of USD)
Accrued compensation
Other long-term liabilities
Total
December 31,
2022
2021
$
$
19 $
16
35 $
28
25
53
The aggregate fair value of PBUs as of December 31, 2022 and 2021 was $46 million and $72 million,
respectively. At December 31, 2022, $11 million of total unrecognized compensation cost related to PBUs not
yet vested is expected to be recognized over the remaining weighted average period of 1.6 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, 2022:
SBUs at December 31, 2021
Granted
Vested and paid out
Forfeited
SBUs at December 31, 2022
Number of
Service
Based Units
689,812
220,640
(253,787)
(26,396)
630,269
The following table presents the classification in the consolidated statements of financial position of
obligations related to outstanding SBUs not yet settled:
(In millions of USD)
Accrued compensation
Other long-term liabilities
Total
December 31,
2022
2021
$
$
9 $
10
19 $
11
11
22
The aggregate fair value of SBUs as of December 31, 2022 and 2021 was $27 million and $32 million,
respectively. At December 31, 2022, $8 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 1.7 years.
Employee Share Purchase Plan
ITC employees are permitted to purchase common shares of Fortis stock under the Fortis ESPP. ITC
Holdings also makes contributions as additional compensation to participating employees’ ESPP accounts. The
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cost of ITC Holdings’ contribution for the years ended December 31, 2022, 2021, and 2020 was less than $1
million, respectively.
14. JOINTLY OWNED UTILITY PLANT/COORDINATED SERVICES
As of December 31, 2022, ITC Holdings was a participant in the following jointly-owned substation assets
and transmission lines:
(In millions of USD except for ownership interest)
Huntley Wilmarth (a)
Cardinal Hickory Creek (b)
Other (c)
ITCTransmission
METC
ITC Midwest
ITC Great Plains
Ownership
Interest
Property, Plant
and Equipment
Accumulated
Depreciation
Construction
Work in Progress
50.0 % $
45.5 %
49.6 %
various
various
49.0 %
57 $
2 $
—
29
58
91
33
—
19
40
17
4
—
144
—
—
1
—
____________________________
(a) Jointly owned between ITC Midwest and Northern States Power Company.
(b) Jointly owned between ITC Midwest, American Transmission Company and Dairyland Power Cooperative.
(c) Jointly owned with various parties.
15. RELATED PARTY TRANSACTIONS
Related Party Receivables and Payables
ITC Holdings may incur charges from Fortis and other subsidiaries of Fortis that are not subsidiaries of ITC
Holdings for general corporate expenses incurred. In addition, ITC Holdings 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. We had receivables from Fortis and such subsidiaries of $1 million and $2 million at December 31,
2022 and 2021, respectively, and payables to Fortis and such subsidiaries of $1 million and less than $1 million
at December 31, 2022 and 2021, respectively.
Related party charges for corporate expenses from Fortis and such subsidiaries are recorded in general and
administrative expense. ITC Holdings had such expense for the year ended December 31, 2022 of $13 million
and for the years ended December 31, 2021 and 2020 of $10 million. Related party billings for services to Fortis
and other subsidiaries recorded as an offset to general and administrative expenses for ITC Holdings were $2
million for each of the years ended December 31, 2022, 2021 and 2020.
Dividends
We paid dividends of $273 million, $232 million and $330 million during the years ended December 31, 2022,
2021 and 2020, respectively, to ITC Investment Holdings. ITC Holdings also paid dividends of $70 million to ITC
Investment Holdings in January 2023.
Intercompany Tax Sharing Agreement
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. During the year
ended December 31, 2022, we paid $11 million to ITC Investment Holdings associated with our income tax
position. During year ended December 31, 2021, we did not make or receive any tax-related payments with ITC
Investment Holdings. During the year ended December 31, 2020, we paid $2 million to ITC Investment Holdings
for matters related to the State of Michigan income taxes.
During the year ended December 31, 2020 we received a payment of $2 million from FortisUS for a tax
refund that originated prior to establishing the tax sharing agreement.
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16. 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 PCBs. 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 proceedings include certain
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 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 with the
FERC under Section 206 of the FPA requesting that the FERC find the MISO regional base ROE rate (the “base
ROE”) for all MISO TO’s, 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
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the formula transmission rates for our MISO Regulated Operating Subsidiaries to 9.15%, reducing the equity
component of our capital structure and terminating the ROE adders approved for certain 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.
On September 28, 2016, the FERC issued the September 2016 Order that set the base ROE at 10.32%,
with a maximum ROE of 11.35%, effective for the period from November 12, 2013 through February 11, 2015
based on a two-step DCF methodology adopted in previous complaint matters for other utilities. The September
2016 Order required our MISO Regulated Operating Subsidiaries to provide refunds, including interest, which
were completed in 2017. Additionally, the base ROE established by the September 2016 Order was to be used
prospectively from the date of that order until a new approved base ROE was established by the FERC. On
October 28, 2016, the MISO TOs, including our MISO Regulated Operating Subsidiaries, filed a request with the
FERC for rehearing of the September 2016 Order regarding the short-term growth projections in the two-step
DCF analysis. Additional impacts to the base ROE for the period of the Initial Complaint and the related accrued
refund liabilities resulted from the November 2019 Order and May 2020 Order issued by the FERC, as
discussed below.
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 ALJ 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 the November 2019 Order and the dismissal of the complaint was reaffirmed in the May 2020
Order, as discussed below.
November 2019 Order
On November 21, 2019, the FERC issued an order in the MISO ROE Complaints which applied a
methodology to the Initial Complaint period that used two financial models to determine the base ROE. The
FERC determined that the base ROE for the Initial Complaint should be 9.88% and the top of the range of
reasonableness for that period should be 12.24% and 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 September 2016 Order
prospectively. In the November 2019 Order, the FERC also dismissed the Second Complaint. Therefore, based
on the November 2019 Order, for the Second Complaint refund period from February 12, 2015 to May 11, 2016,
no refund is due. As a result, in 2019, we reversed the aggregate estimated current liability we had previously
recorded for the Second Complaint. In addition, for the period from May 12, 2016 to September 27, 2016, no
refund is due because no complaint had been filed for that period. The FERC ordered refunds to be made in
accordance with the November 2019 Order. The MISO TOs, including our MISO Regulated Operating
Subsidiaries, and several other parties filed requests for rehearing of the November 2019 Order. The MISO TOs
asserted that the methodology applied by the FERC in the November 2019 Order does not allow the MISO TOs
to earn a reasonable rate of return on their investment, as required by precedent. On January 21, 2020, the
FERC issued an order granting rehearing of the November 2019 Order for further consideration.
May 2020 Order
On May 21, 2020, the FERC issued an order on rehearing of the November 2019 Order. In this order, the
FERC revised its November 2019 Order methodology, finding that three financial models should be used to
determine the base ROE, among other revisions. 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 September 2016 Order prospectively. The
FERC ordered refunds to be made in accordance with the May 2020 Order. Refund settlements were finalized
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during the three months ended March 31, 2022. In the May 2020 Order, the FERC also reaffirmed its decision to
dismiss the Second Complaint and its finding that no refunds would be ordered on the Second Complaint.
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.
Financial Statement Impacts
As of December 31, 2021, we had recorded an aggregate current regulatory asset and liability of $1 million
and less than $1 million, respectively, in the consolidated statements of financial position. These impacts reflect
amounts owed from or due to customers under the terms outlined in the May 2020 Order and the November
2019 Order on the Initial Complaint and the periods subsequent to the September 2016 Order. During the year
ended December 31, 2022, we received net settlement payments of less than $1 million owed from customers
related to this matter. During the years ended December 31, 2021 and 2020, we refunded net settlement
payments of $5 million and $31 million, respectively, due to customers related to this matter. As of December
31, 2022, there are no remaining regulatory assets or liabilities recorded related to this matter.
It is possible that the base ROE established in the May 2020 Order may be revised and that we could be
required to provide additional material refunds upon resolution of the proceedings. We are determining next
steps in response to the August 2022 D.C. Circuit Court decision and awaiting action by the FERC in these
proceedings to provide further insight into possible changes to our base ROE and the periods for which a
revised ROE applies. We cannot predict whether these proceedings will have a material impact, or estimate the
possible impact, on our financial condition, results of operations or cash flows.
The recognition of the obligations associated with the MISO ROE Complaints resulted in the following
impacts to the consolidated statements of comprehensive income:
(In millions of USD)
Revenue increase
Interest expense decrease
Estimated net income increase
Year Ended December 31,
2022
2021
2020
$
— $
—
—
— $
—
—
32
(3)
25
See Note 5 for a summary of our base ROE and incentive adders for transmission rates. As of December 31,
2022, our MISO Regulated Operating Subsidiaries had a total of approximately $5 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 $5 million.
Purchase Obligations
At December 31, 2022, we had purchase obligations of $137 million representing commitments for materials,
services and equipment that had not been received as of December 31, 2022, primarily for construction and
maintenance projects for which we have an executed contract. Of these purchase obligations, $125 million is
expected to be paid in 2023, 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.
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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.
The OSA provides that when ITC Midwest upgrades 34.5 kV facilities to higher operating voltages it may notify
IP&L of the change and the OSA is no longer applicable to those facilities.
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 21.0%, 24.0% and 25.4%, respectively, or $310 million, $354 million and $375 million,
respectively, of our consolidated billed revenues for the year ended December 31, 2022. This portion of total
billed revenues of DTE Electric, Consumers Energy and IP&L include the collection of 2020 revenue accruals
and deferrals and exclude any amounts for the 2022 revenue accruals and deferrals that were included in our
2022 operating revenues but will not be billed to our customers until 2024. Under DTE Electric’s and
Consumers Energy’s current rate structure, DTE Electric and Consumers Energy include in their retail rates the
actual cost of transmission services provided by ITCTransmission and METC, respectively, in their billings to
their customers, effectively passing through to end-use consumers the total cost of transmission service. IP&L
currently includes in their retail rates an allowance for transmission services provided by ITC Midwest in their
billings to their customers. However, any financial difficulties experienced by DTE Electric, Consumers Energy
or IP&L may affect their ability to make payments for transmission service to ITCTransmission, METC, and ITC
Midwest, which could negatively impact our business. MISO, as our MISO Regulated Operating Subsidiaries’
billing agent, bills DTE Electric, Consumers Energy, IP&L and other customers on a monthly basis and collects
fees for the use of the MISO Regulated Operating Subsidiaries’ transmission systems. SPP is the billing agent
for ITC Great Plains and bills transmission customers for the use of ITC Great Plains transmission systems.
MISO and SPP have implemented strict credit policies for its members’ customers, which include customers
using our transmission systems. Specifically, MISO and SPP require a letter of credit or cash deposit equal to
the credit exposure, which is determined by a credit scoring model and other factors, from any customer using a
member’s transmission system.
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17. 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:
(In millions of USD)
Cash and cash equivalents
Restricted cash included in:
Other non-current assets
Total cash, cash equivalents and restricted cash
December 31,
2022
2021
2020
2019
4 $
5 $
4 $
2
6 $
2
7 $
2
6 $
$
$
4
2
6
Restricted cash included in other non-current assets 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.
Supplementary Cash Flow Information
(In millions of USD)
Supplementary cash flows information:
Interest paid (net of interest capitalized)
Income taxes paid
Income tax refunds received
Year Ended December 31,
2022
2021
2020
$
247 $
237 $
236
11
—
117
37
1
—
—
140
30
3
2
2
135
27
—
Supplementary non-cash investing and financing activities:
Additions to property, plant and equipment and other long-lived assets (a)
Allowance for equity funds used during construction
Other
____________________________
(a) Amounts consist of current and accrued liabilities for construction, labor, materials and other costs that have
not been included in investing activities. These amounts have not been paid for as of December 31, 2022,
2021 or 2020, 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.
18. SEGMENT INFORMATION
We identify reportable segments based on the criteria set forth by the FASB regarding disclosures about
segments of an enterprise, 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.
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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.
2022
(In millions of USD)
Operating revenues
Depreciation and amortization
Interest expense, net
Income (loss) before income taxes
Income tax provision (benefit)
Net income
Property, plant and equipment, net
Goodwill
Total assets (a)
Capital expenditures
2021
(In millions of USD)
Operating revenues
Depreciation and amortization
Interest expense, net
Income (loss) before income taxes
Income tax provision (benefit)
Net income
Property, plant and equipment, net
Goodwill
Total assets (a)
Capital expenditures
Regulated
Operating
ITC Holdings
Reconciliations/
Subsidiaries
and Other
Eliminations
Total
$
1,503 $
1 $
(38) $
1,466
295
134
736
179
557
10,630
950
12,005
933
—
135
(148)
(33)
442
7
—
6,378
—
—
—
—
—
(557)
—
—
(6,252)
—
295
269
588
146
442
10,637
950
12,131
933
Regulated
Operating
ITC Holdings
Reconciliations/
Subsidiaries
and Other
Eliminations
Total
$
1,386 $
1 $
(38) $
1,349
231
123
691
173
518
9,954
950
11,317
841
1
129
(158)
(46)
406
7
—
6,134
—
—
(1)
—
—
(518)
—
—
232
251
533
127
406
9,961
950
(6,006)
11,445
(7)
834
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2020
(In millions of USD)
Operating revenues
Depreciation and amortization
Interest expense, net
Income (loss) before income taxes
Income tax provision (benefit)
Net income
Property, plant and equipment, net
Goodwill
Total assets (a)
Capital expenditures
____________________________
Regulated
Operating
ITC Holdings
Reconciliations/
Subsidiaries
and Other
Eliminations
Total
$
1,333 $
1 $
(36) $
1,298
218
118
683
179
504
9,319
950
10,710
886
1
122
(140)
(43)
407
8
—
5,830
—
—
—
—
—
(504)
—
—
219
240
543
136
407
9,327
950
(5,715)
10,825
(1)
885
(a) Reconciliation of total assets results primarily from differences in the netting of deferred tax assets and
liabilities in our segments as compared to the classification in our consolidated statements of financial
position.
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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
ITEM 9A. CONTROLS AND PROCEDURES.
Management’s Report on Internal Control Over Financial Reporting is included in Item 8. of this Form 10-K.
Disclosure Controls and Procedures
We maintain disclosure controls and procedures that are designed to provide reasonable assurance that
material information required to be disclosed in our reports that we file or submit under the Exchange Act, is
recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms,
and that such information is accumulated and communicated to our management, including our Chief Executive
Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required financial
disclosure. In designing and evaluating the disclosure controls and procedures, management recognized that a
control system, no matter how well designed and operated, can provide only reasonable, not absolute,
assurance that the objectives of the control system are met. Because of the inherent limitations in all control
systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud,
if any, with a company have been detected.
As of the end of the period covered by this report, we carried out an evaluation, under the supervision and
with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of
the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15
of the Exchange Act. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer
concluded that our disclosure controls and procedures are effective, at the reasonable assurance level.
Changes in Internal Control over Financial Reporting
There have been no changes in our internal control over financial reporting during the quarter ended
December 31, 2022 that have materially affected, or are reasonably likely to materially affect, our internal
control over financial reporting.
ITEM 9B. OTHER INFORMATION.
None.
ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS.
Not Applicable.
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PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.
DIRECTORS
Our Bylaws provide for the election of directors at each annual meeting of shareholders. Each director
serves until the next annual meeting and until his or her successor is elected and qualified, or until his or her
resignation or removal.
The Board must consist of the Chief Executive Officer of the Company (Ms. Apsey), a minority of
representatives of Fortis (Mr. Hutchens and Ms. Perry) and a majority of directors who are independent of
Fortis. Mr. Laurito previously served as a Fortis representative until his retirement from Fortis on December 31,
2021. Due to Mr. Laurito’s affiliation with Fortis, he will remain a non-independent director for at least 3 years
from his retirement from 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, 53. Ms. Apsey became President and Chief Executive Officer of the Company in 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 five 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 five
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 President and
Chief Executive Officer of the Company.
Leanne M. Bell, 62. 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 Ventient Energy Services Limited, Nassau Financial Group and
Third Coast Midstream, LLC. She previously served on the board of 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.
Robert A. Elliott, 67. 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 has been
a board member of UNS Energy Corporation, a subsidiary of Fortis, since 2014, serving as the Chair of the
Board until 2021. Mr. Elliott currently serves on the board of directors of AAA Mountain West Group and has
served since 2016. He is the Chair of the board of directors of AAA Auto Club Partners. 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, 57. 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
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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 and University of Minnesota,
Institute on the Environment. 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 on the Governance and Human Resources
Committee.
Lt. Gen. Ronnie Hawkins, Jr., USAF, Retired, 67. 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. The Board selected Lt. Gen.
Hawkins Jr. due to his vast knowledge of cybersecurity and information systems as well as his leadership
experience. Mr. Hawkins serves on the Governance and Human Resources Committee.
David G. Hutchens, 56. 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, 66. 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, and UNS Energy. He currently serves on the
boards of Bowman Consulting Group, where he serves as Chair of the Compensation Committee, Belize
Electricity Ltd., 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.
Jocelyn H. Perry, 52. 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, 64. 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 is Senior Executive Vice
President, Private Client Group & Regional Banking Director and Chair of Michigan for Huntington National
Bank. 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
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Michigan, from 2013 to 2016. Ms. Pierce currently serves as a board member of Barton Malow Enterprises,
Penske Automotive Group and American Axle & Manufacturing, Inc. She also serves as the vice chair of
Business Leaders of Michigan, chair of Henry Ford Health Foundation and chair of Detroit Economic Club.
Previously, Ms. Pierce served as chair of the Detroit Financial Advisory Board and chair of Henry Ford Health
System. 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, 67. 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, 66. 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 chairs the University of North Carolina at Chapel Hill’s
(“UNC”) Ackland Museum board in addition to serving as an Executive Residence for Economic Development at
UNC. 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 as the Chair of the Governance and Human Resources Committee.
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, 53. Ms. Apsey’s background is described above under “Directors.”
Gretchen L. Holloway, 48. 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 for the Fortis subsidiary, Caribbean Utilities Company, where she is also a member of the
Audit Committee. Ms. Holloway also serves as a member of the Finance & Audit Committee for the Children’s
Hospital of Michigan Foundation, a member of Women Thrive Advisory Board and a member of the Board of
Directors of Inforum.
Jon E. Jipping, 56. Jon E. Jipping has served as Executive Vice President since February 2022. He was
named Executive Vice President and Chief Operating Officer in June 2007 and was responsible for
field construction and
transmission system planning, system operations, engineering, supply chain,
maintenance, and information technology. Mr. Jipping joined the Company as Director of Engineering in March
2003, was appointed Vice President - Engineering in 2005 and was named Senior Vice President in February
2006. Mr. Jipping currently serves on the board of Wataynikaneyap Power PM Inc., an entity owned by
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FortisOntario, Inc., a subsidiary of Fortis, which was created to develop and operate transmission to connect
remote First Nation communities to the electrical grid in northwestern Ontario, Canada. He was appointed to the
Michigan Technological University Board of Trustees as a Board Member in 2020. As noted in our Current
Report on Form 8-K filed with the SEC on December 6, 2022, Mr. Jipping has announced his resignation as
Executive Vice President and retirement from the Company, effective March 3, 2023.
Brian Slocum, 46. 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 the Chair of
the Reliability Issues Steering Committee of NERC.
Christine Mason Soneral, 50. Christine 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 served on the
board of Citizens Research Council, a privately funded, not-for-profit public affairs research organization from
2014 to 2020. Ms. Mason Soneral also 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.
Krista K. Tanner, 48. Ms. Tanner has served as our Senior Vice President and Chief Business Officer since
February 2019. Ms. Tanner is responsible for strategic direction, customer service, local government and
community affairs and financial performance for four of the Company’s operating subsidiaries: ITC Midwest, ITC
Great Plains, ITCTransmission and METC. In addition, she is responsible for federal regulatory and legislative
affairs and marketing and communications. 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 - 2011. Ms. Tanner previously served as a member of the
Board of Directors of the Midwest Reliability Organization from 2017 to 2019. Ms. Tanner currently serves as a
member of the Board of Directors of Delta Dental of Iowa and a member of the Board of Directors for the
American Clean Power Association.
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.
ITEM 11. EXECUTIVE COMPENSATION.
COMPENSATION OF EXECUTIVE OFFICERS AND DIRECTORS
Compensation Discussion and Analysis
The following Compensation Discussion and Analysis describes the elements of compensation for our Chief
Executive Officer (or “CEO”), our Chief Financial Officer and the three other most highly compensated executive
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officers who were serving as such at December 31, 2022. We refer to these individuals collectively as the
“named executive officers” (or “NEOs”).
The Company’s named executive officers for 2022 were:
Name
Linda H. Apsey
Gretchen L. Holloway
Jon E. Jipping
Christine Mason Soneral
Krista Tanner
Executive Summary
Position
President and Chief Executive Officer
Senior Vice President and Chief Financial Officer
Executive Vice President
Senior Vice President, General Counsel, Corporate Secretary and Chief
Compliance Officer
Senior Vice Present and Chief Business Officer
The Governance and Human Resources Committee (the “Committee”) is responsible for determining the
compensation of our NEOs and administering the plans in which the NEOs participate. The goals of our
compensation system are to attract first-class executive talent in a competitive environment and to motivate and
retain key employees who are crucial to our success by rewarding Company and individual performance that
promotes long-term sustainable growth and increases 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 2022:
• Base salary increases. Base salary increases were provided to each of our NEOs in 2022 to reward
individual performance and to remain competitive and aligned with market.
• Annual cash incentive bonuses. The NEOs earned cash incentive bonuses for 2022 performance of
approximately 160% of target. This was based on achieving 90% of the performance targets established
under the ACPB in early 2022 and achievement of certain performance factors which resulted in a bonus
multiplier of 1.78x. 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 in January
2022. 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 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 shareholder value;
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• 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 2022, 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.
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,
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. The Committee adopted this strategy in October 2019. In
November 2021, 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 with the targeted competitive range, and in
some cases, exceeded the targeted competitive position. Competitive positioning reflects median base salaries
and above median target bonus and 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
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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 2022 target pay levels. The Committee did not determine the mix of compensation elements
using a pre-set formula. In setting executive compensation levels, the Committee retained full discretion to
consider or disregard data collected through benchmarking studies. In addition to the market data,
compensation decisions also considered individual and Company performance, retention concerns, the
importance of the position, internal equity and other factors.
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 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 summarize 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 2022 base salaries for the NEOs, including any year-over-year change, were:
NEO
2021 Base
Salary
2022 Base
Salary
Percent
Increase
Linda H. Apsey
Gretchen L. Holloway
Jon E. Jipping
Christine Mason Soneral
Krista Tanner
$
840,500 $
865,000
411,700
597,500
399,800
354,900
422,000
606,500
409,800
370,900
2.9 %
2.5 %
1.5 %
2.5 %
4.5 %
Ms. Tanner’s higher percentage increase reflects her expanding role and responsibilities.
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.
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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 maximum goals were considered “stretch” goals with lower expectation of achievement. The bonus
goal targets were designed to be challenging to meet, while remaining achievable.
For 2022, 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.
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 2022, 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
Financial
20%
Maximum
Potential
Payout
Goal
Non-field Operation
and Maintenance
Expense and
General and
Administrative
Expenses
Rationale for Goal
Controlling general
and administrative
expenses is an
important part of
controlling rates
charged to
transmission
customers.
Rationale for Target Goal
Target is based on the
2022 Board-approved
budget.
Non-Field O&M and
G&A expense at or
under budget of $161M.
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
2022 Board-approved
budget.
Adjusted Net Income at
or above $544M to
achieve 10%;
Adjusted Net Income at
or above $517M to
achieve 5%.
Potential
Payout
2022
Results
10 % $141M
Actual
Payout
10%
5% - 10% $554M
10%
Total
20 %
20%
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Safety & Compliance goals represented 15% of the total maximum annual bonus target and included specific
measures for Lost Time, Recordable Incidents and Security.
Potential
Payout
5 %
2022 Results
1
Actual
Payout
5%
5 %
0
5%
5 % Completed
5%
Category
Goal
Safety as
measured by
lost time
Rationale for Goal
Maintaining the
safety of our
employees and
contractors is a
core value and
is at the
foundation of
our success.
Safety as
measured by
recordable
incidents
Maintaining the
safety of our
employees and
contractors is a
core value and
is at the
foundation of
our success.
Safety &
Compliance
15% Maximum
Potential Payout
Security
Maintaining
cyber security is
critical to
ensuring system
reliability and
ongoing
operations.
Rationale for Target
Target number of
incidents remained the
same as prior years
and was based on
industry top decile
performance, which
reflects an aggressive
view and philosophy
on the importance of
safety.
2 or fewer lost work
day cases for injuries
to Company
employees and
specified contract
employees.
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.
7 or fewer recordable
incidents for injuries to
Company employees
and specified contract
employees.
Goal focused on
implementing updated
security objectives.
Emphasized securing
our information
systems and helping
protect our most
important assets.
Implementation of the
2022 Cyber Security
Plan, as presented to
and approved by the
Board of Directors.
Total
15 %
15 %
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The Culture goal represents 5% of the total maximum annual bonus target and includes the implementation
of specific inclusion and diversity goals.
Category
Culture
Goal
Inclusion and
Diversity
5% Maximum
Potential
Payout
Total
Rationale for Goal
Rationale for Target Goal
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.
Potential
Payout
2022 Results
5 % Completed
Actual
Payout
5%
5 %
5%
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System Performance goals represented 60% of the total maximum annual bonus target and included specific
measures for System Outages, Maintenance Plans and Capital Project Plan.
Category
Goal
Outage
frequency
Rationale for
Goal
Reducing and
limiting
system
outages are
critical to
ensuring
system
reliability.
System
Performance
60%
Maximum
Potential
Payout
Field
Operation
and
Maintenance
Plan
Performing
necessary
preventive
maintenance
is critical to
ensuring
system
reliability.
Capital
Project Plan
Performing
necessary
system
upgrades is
critical to
ensuring
system
reliability,
providing a
robust
transmission
grid and
delivering
financial
performance.
Potential
Payout
2022 Results
15 % ITCTransmis
Actual
Payout
5%
sion - 18
METC - 24
ITC Midwest
- 41/32
15 % All high
15%
priority Field
O&M
initiatives
completed
under budget
at $86M
15 - 30%
$912M
30%
Rationale for Target
Target reduced by 1 for ITC
Transmission and by 2 for ITC
Midwest, unchanged from prior
year for METC; all targets
aligned with industry benchmark
data. Number of Forced,
Sustained Line Outages,
excluding the "External" cause
classification, for:
ITCTransmission (12 or fewer,
representing top decile
performance);
METC (23 or fewer, representing
top decile performance);
ITC Midwest (57 or fewer,
representing top decile
performance, no more than 46 at
the 69kV level representing top
quartile performance.);
Each target is worth 5%.
Target is reflective of goal to
complete the normal
maintenance schedule of high
priority maintenance activities.
Complete high priority 2022 Field
O&M Initiatives for:
ITCTransmission (15)
METC (13)
ITC Midwest (10)
Each target worth 5%.
Payout reduced by 5% if not at
or under Field O&M overall
maintenance budget of $92M.
Target is based on accrued
capital investment.
The maximum payout represents
the risk-adjusted capital
investment plan for 2022, with a
threshold level also established.
Complete $802M of the 2022
Capital Project Plan to achieve
30%; Complete $760M to
achieve 15%.
Total
Total Bonus (as a percent of target bonus level)
____________________________
60 %
100 %
50%
90%
(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:
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(In millions of USD)
Net income of Regulated Operating Subsidiaries
Adjustments related to income taxes
Adjusted net income
$
$
2022
557
(3)
554
Additionally, our executives, including the NEOs, are eligible for an executive bonus multiplier. To further
motivate management to provide value to the shareholder, in 2022 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
Capital Project Plan
Adjusted Consolidated
Net Income (1)
Strategic Plan
Objectives
Inclusion & Diversity
Plan
Bonus Multiplier
Threshold
$844M
$438M
Create 6
Objectives
Achieve 1
Goal
____________________________
Maximum Achievement Multiplier
$912M
$912M
2.00x
Weight
30%
Result
0.60x
$460M
Achieve 4
Objectives
Achieve 3
Goals
$450M
Achieved 2
Objectives
Achieved 3
Goals
1.75x
1.50x
2.00x
30%
30%
10%
0.53x
0.45x
0.20x
1.78x
(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)
Net income
Adjustments related to income taxes
Other
Adjusted consolidated net income
$
$
2022
442
7
1
450
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 1.78x. This performance factor was applied to the ACPB
factor of 90% to produce a final payment of approximately 160% 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 2022 were 100% of base salary for each NEO.
Long-Term Equity Incentive
The Committee provides and maintains a long-term equity incentive program under the 2017 Omnibus Plan,
the Executive Omnibus Plan and the Fortis Inc. 2020 Restricted Share Unit Plan. In February 2022, the
Committee approved grants of SBUs and PBUs to the NEOs, based on our CEO’s recommendation (except for
grants to the CEO), and also on the Committee’s assessment of the performance of the Company and the
executive. 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 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. Each unit is generally equivalent to one share of Fortis stock (as
traded on the Toronto Stock Exchange) and earned PBU units are payable in cash and earned SBU units are
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payable in cash or Fortis common stock. SBUs vest over the same three-year performance period based on
service. Awards to the CEO were also presented to the Board of Directors by the Committee and ratified by the
Board of Directors (other than the CEO). The amounts and more detailed terms of the 2022 SBU and PBU
grants made under the Fortis Inc. 2020 Restricted Share Unit Plan and the Executive Omnibus Plan are
described in the narrative following the Grants of Plan-Based Awards Table. 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 2022 awards were made, the award
values were targeted to be:
NEO
Ms. Apsey
Ms. Holloway
Mr. Jipping
Ms. Mason Soneral
Ms. Tanner
Grant Value
Percent of
Salary
250 %
175 %
175 %
175 %
175 %
In determining the size of grants under the long-term incentive program and the award mix, the Committee
considered market practice, the recommendation of the CEO (with respect to grants other than to the CEO) in
light of comparisons to benchmarking data, expense to the Company and the practice of other U.S. Fortis
subsidiary companies.
Other Components of Our Executive Compensation Program
Pension Benefits. As is common in our industry and as established pursuant to our initial formation
requirements included in the acquisition agreement with DTE Energy for ITCTransmission, we maintain a tax-
qualified defined benefit retirement plan for eligible employees, comprised of a traditional pension component
and a cash balance component. All employees, including the NEOs, participate in either the traditional
component or the cash balance component. We have also established a supplemental nonqualified,
noncontributory retirement benefit plan for selected management employees: the Executive Supplemental
Retirement Plan, or ESRP, in which all of the NEOs participate. This plan provides for benefits that supplement
those provided by our qualified defined benefit retirement plan. Benefits payable to the NEOs pursuant to the
retirement plans are set by the terms of those plans. The Committee exercises no regular discretionary authority
in the determination of benefits. The retirement plans may be modified, amended or terminated at any time,
although no such action may reduce a NEO’s earned benefits. See “Pension Benefits” for information regarding
participation by the NEOs in our retirement plans as well as a description of the terms of the plans.
Benefits and Perquisites. The NEOs participate in a variety of benefit programs, which are designed to
enable us to attract and retain our workforce in a competitive marketplace. These programs include our Savings
and Investment Plan, which consists of an employee deferral contribution component and an employer safe-
harbor matching contribution component.
Our NEOs are provided a limited number of perquisites in addition to benefits provided to our other
employees. The purpose of these perquisites is to minimize distractions from the NEOs’ attention to important
Company initiatives, to facilitate their access to work functions and personnel, and to encourage interactions
among NEOs and others within professional, business and local communities. NEOs are provided perquisites
such as auto allowance, financial, estate and legal planning, income tax return preparation, annual physical,
club memberships, 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
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of recognition and reward for their efforts. Because such tickets have already been purchased, we do not
believe that there is any aggregate incremental cost to the Company if a NEO uses a ticket for personal
purposes.
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.
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 stock ownership by the fifth anniversary of when the guidelines first became applicable to the individual.
The current levels are as follows:
Position
Chief Executive Officer
Executive and Senior Vice Presidents
Vice Presidents
Ownership Level
2x annual base salary
1.5x annual base salary
1x annual base salary
The securities that qualify for the purpose of determining compliance with the policy are common shares of
Fortis stock 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 or (ii) such time as the executive is again in compliance with the guidelines. As of December 31,
2022, 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
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Summary Compensation
The following table provides a summary of compensation paid or accrued by the Company and its
subsidiaries to or on behalf of the NEOs for services rendered by them during each of the last three calendar
years, as required by applicable SEC rules and regulations. The material terms of plans and agreements
pursuant to which certain items set forth below were paid are discussed elsewhere in Compensation of
Executive Officers and Directors.
Summary Compensation Table
Stock Awards ($)
(1)
Non-Equity
Incentive Plan
Compensation
($) (2)
Change in
Pension Value &
Non-qualified
Deferred
Compensation
Earnings
($)(3)
All Other
Compensation
($) (4)
(e)
(f)
(g)
(h)
Salary ($)
(c)
Total ($)
(i)
$
864,999 $
2,162,565 $
1,385,730 $
— $
150,088 $
4,563,382
843,732
819,630
422,000
413,284
399,570
606,500
599,799
589,347
409,799
401,377
396,285
370,900
356,265
339,797
2,086,868
2,036,614
738,532
715,560
695,003
1,061,383
1,038,492
1,023,422
717,154
694,865
688,169
649,076
616,837
593,288
1,370,015
1,151,376
676,044
671,071
561,296
971,613
973,925
826,564
656,500
651,674
555,793
594,182
578,487
479,176
184,341
359,039
—
101,514
181,670
—
211,095
522,326
—
94,802
200,948
—
94,877
123,653
100,652
84,625
39,579
36,871
36,936
39,399
38,499
38,199
40,637
38,746
35,950
36,726
36,113
34,620
4,585,608
4,451,284
1,876,155
1,938,300
1,874,475
2,678,895
2,861,810
2,999,858
1,824,090
1,881,464
1,877,145
1,650,884
1,682,579
1,570,534
Name
(a)
Linda H. Apsey,
President & CEO
Gretchen L. Holloway
SVP & CFO
Jon E. Jipping,
EVP & COO
Christine Mason Soneral,
SVP, General Counsel,
Secretary & CCO
Krista Tanner,
SVP & CBO
Year
(b)
2022
2021
2020
2022
2021
2020
2022
2021
2020
2022
2021
2020
2022
2021
2020
____________________________
(1) The amounts reported in this column represent the grant date fair value of PBU awards and SBU awards
granted to the NEOs under the 2017 Omnibus Plan, the Executive Omnibus Plan and the Fortis Inc. 2020
Restricted Share Unit 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 (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, see “Grants of Plan-Based Awards.” The value of the 2022 PBU awards at the grant date
assuming that the highest level of performance conditions will be achieved are as follows:
Ms. Apsey
Ms. Holloway
Mr. Jipping
Ms. Mason Soneral
Ms. Tanner
$
2,883,380
984,703
1,415,143
956,180
865,409
(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 2022, 2021 and 2020. For information regarding the
corporate goals for 2022, 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
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
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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 2.74% in 2020,
3.01% for 2021 and 5.57% for 2022. Due to the 256 basis point increase in discount rates during 2022, the
change in present value declined since 12/31/2021 and therefore the 2022 reported change in pension
values are zero for all.
(4) All Other Compensation includes amounts for auto allowance, financial, estate and legal planning, income
tax return preparation, annual physical, club memberships, event tickets, 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 2022, 2021 and 2020 are itemized in the table below as required by applicable
SEC rules.
Name
Linda H. Apsey
Gretchen L. Holloway
Jon E. Jipping
Christine Mason Soneral
Krista Tanner
401(k) Match
Personal Use of
Company
Aircraft
Other Benefits
Total
$
18,300 $
104,603 $
27,185 $
17,400
17,100
18,300
15,550
15,450
18,300
17,400
17,100
18,300
15,550
15,450
15,357
14,659
14,120
54,461
40,440
—
—
—
—
—
—
—
—
—
—
—
—
28,791
27,085
21,279
21,321
21,486
21,099
21,099
21,099
22,337
23,196
20,500
21,369
21,454
20,500
150,088
100,652
84,625
39,579
36,871
36,936
39,399
38,499
38,199
40,637
38,746
35,950
36,726
36,113
34,620
Year
2022
2021
2020
2022
2021
2020
2022
2021
2020
2022
2021
2020
2022
2021
2020
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. Because such tickets have already been purchased, we do
not believe that there is any aggregate incremental cost to the Company if a NEO uses a ticket for personal
purposes.
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Grants of Plan-Based Awards
The following table sets forth information concerning each grant of an award made to a NEO during 2022.
Estimated Future Payouts Under
Non-Equity Incentive Plan Awards
Estimated Future Payouts Under
Equity Incentive Plan Awards
Award
Type
Threshold
($)
(c)
Target
($)(1)
(d)
Maximum
($)(1)
Threshold
(#)(2)
Target
(#)(2)
Maximum
(#)(2)
(e)
(f)
(g)
(h)
(i)
(j)
$
— $
— $
—
—
—
14,962 $ 720,875
Name
(a)
Linda H. Apsey
Gretchen L.
Holloway
Jon E. Jipping
Christine Mason
Soneral
Krista Tanner
Grant
Date
(b)
1/1/2022
1/1/2022
1/1/2022
1/1/2022
1/1/2022
1/1/2022
1/1/2022
1/1/2022
1/1/2022
1/1/2022
SBU
PBU
ACPB
SBU
PBU
ACPB
SBU
PBU
ACPB
SBU
PBU
ACPB
SBU
PBU
ACPB
—
—
—
865,000
1,730,000
—
—
—
—
422,000
844,000
—
—
—
—
606,500
1,213,000
—
—
—
—
409,800
819,600
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
14,962
29,923
59,846
—
—
—
—
—
—
5,110
10,219
20,438
—
—
—
—
—
—
7,343
14,686
29,372
—
—
—
—
—
—
4,962
9,923
19,846
—
—
—
—
—
—
4,491
8,981
17,962
All Other
Stock
Awards:
Number
of Shares
of Stock
or Units
(#)
Grant
Date Fair
Value of
Stock and
Option
Awards
($)(3)
—
—
1,441,690
—
5,110
246,181
—
—
492,351
—
7,344
353,812
—
—
707,571
—
4,962
239,064
—
—
478,090
—
4,491
216,371
—
—
432,705
—
370,900
741,800
—
—
—
____________________________
(1) The amount shown in Column (d) represents the potential payout for the ACPB based on “target bonus
levels.” The amount payable assuming maximum achievement of all bonus goals, including the bonus
multiplier, is set forth in column (e). Actual dollar amounts paid are disclosed and reported in the “Summary
Compensation Table” as Non-Equity Incentive Plan Compensation. For more information regarding the
ACPBs, see “Compensation Discussion and Analysis — Key Components of Our NEO Compensation
Program — Annual Corporate Performance Bonus.”
(2) Payment of each PBU award is contingent on meeting performance targets based on (1) Fortis Total
Shareholder Return in comparison to the Total Shareholder Return during the performance period for each
of the companies that comprise the 2022 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 performance share awards, 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. 2020 Restricted Share
Unit Plan and Executive Omnibus Plan, respectively, with a grant date of January 1, 2022. The SBUs and
PBUs reflected here are recorded at fair value at the date of grant, which was $48.18 per share. Share fair
values were converted from Canadian Dollars to US Dollars using the “Award Conversion Rate” defined in
the plans.
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 did not have a pre-established targeted
allocation of total direct compensation.
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The Committee had the power to award SBUs in the form of equity or cash under the Fortis Inc. 2020
Restricted Share Unit Plan and PBUs in the form of equity or cash under the Executive Omnibus Plan with the
terms of each award set forth in a written agreement with the recipient. Grants made in 2022 to the NEOs were
made under their respective plans pursuant to terms stated in the SBU and PBU award agreements.
Performance-Based Unit Award Agreements
The PBU award agreements entered into with each NEO on January 1, 2022 (the “PBU Grant Date”) (each a
“PBU Agreement”) provide generally that the award will vest on January 1, 2025 (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
related to the Fortis Carbon Reduction Performance goal (the “CRP goal”). The PBUs will become earned as
set forth in the following table:
Measurement Category
Goal at
Threshold
Shares at
Threshold
Goal at
Target
Fortis Total Shareholder
Return
Cumulative Consolidated Net
Income
Fortis Carbon Reduction
Performance
30th
percentile
99% of
Target
Reduction
of 5M
tonnes
50% of TSR
Target Units
50% of
CCNI
Target Units
50% of
CRP Target
Units
50th
percentile
100% of
Target
Reduction
of 6.7M
tonnes
Shares at
Target
100% of
TSR Target
Units
100% of
CCNI
Target Units
100% of
CRP Target
Units
Goal at
Maximum
Shares at
Maximum
85th
percentile
103% of
Target
Reduction
of 10M
tonnes
200% of
TSR Target
Units
200% of
CCNI
Target Units
200% of
CRP Target
Units
The performance period for the award is January 1, 2022 through December 31, 2024 (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 2022 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 25 U.S. and Canadian public utility companies:
Alliant Energy Corporation
Ameren Corporation
Atmos Energy Corporation
Canadian Utilities Limited
CenterPoint Energy Inc.
CMS Energy Corporation
Consolidated Edison Inc.
DTE Energy Company
Edison International
Emera Incorporated
Entergy Corporation
Evergy, Inc.
Eversource Energy
FirstEnergy Corp.
Hydro One Limited
NiSource Inc.
OGE Energy Corp.
PG&E Corporation
Pinnacle West Capital Corporation
PPL Corporation
Public Service Enterprise Group Inc.
Sempra Energy
UGI Corporation
WEC Energy Group, Inc.
Xcel Energy Inc.
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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 (if necessary, converted
into U.S. dollars based on the Award Conversion Rate as defined in the Executive Omnibus Plan)
B: Calculate the Market Price as of the last day of the Payment Criteria Period (if necessary, converted
into U.S. dollars based on the Award Conversion Rate)
C: Calculate the total dividends paid per share of its common stock (or equivalent security) during the
Payment Criteria Period (if necessary, converted into U.S. dollars based on the Award Conversion
Rate)
Total Shareholder Return = ((B - A) + C)/A
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.
If the grantee ceases to be employed before the PBU Vesting Date due to death, disability or
“Retirement” (as defined below), and the grantee has been employed with the Company for 15 years or more,
the grantee will receive, following the PBU Vesting Date, the number of PBUs to which the grantee would have
otherwise been entitled if the grantee had remained employed through the PBU Vesting Date. If the grantee
ceases to be employed before the PBU Vesting Date due to death, disability or Retirement, and the grantee has
been employed with the Company for less than 15 years, the grantee will receive, following the PBU Vesting
Date, (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. If termination occurs prior to the PBU Vesting Date other
than as a result of death, disability or Retirement, grantee will forfeit the award.
“Retirement” is defined to mean termination of grantee’s employment with the Company upon or after
completing 10 years of service with the Company after attaining the age of 45 if 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 Executive Omnibus Plan, the Governance and 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”). 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 payout if there is an involuntary
employment action within 24 months following the Change of Control. In the event of a Change of Control and
an involuntary employment action 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
payout percentage for outstanding PBUs is the product of (i) the higher of (A) 100% of the target number of
PBUs in the award or (B) the actual payout percentage based on the Committee’s assessment of performance
of the payment criteria from the beginning of the Payment Criteria Period for the award through the date of the
Change of Control, multiplied by (ii) a fraction, the numerator of which is the number of days elapsed in the
Payment Criteria Period for the award through the date on which the Change of Control occurred and the
denominator of which is the total number of days in the payment criteria period for the award.
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Grantees are entitled to receive additional PBUs equal to the “dividend equivalent” when a cash dividend is
paid on common shares of Fortis stock (each a “Common Share”). 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, converted to U.S. dollars based on the Award Conversion Rate.
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.
Service-Based Unit Award Agreements
The SBU award agreements entered into with each NEO on January 1, 2022 (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 upon the earlier of (i) January 1, 2025 (the “SBU Vesting Date”) or (ii) the grantee's death, disability or
“Retirement.” If the grantee ceases to be employed before the SBU Vesting Date due to death, disability or
Retirement, and 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. If the grantee ceases to be employed before the SBU
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 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. If termination occurs prior to the
SBU Vesting Date other than as a result of death, disability or Retirement, 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. 2020 Restricted Share Unit 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 payout if there is an involuntary employment action within 24 months following the Change of
Control. In the event of a Change of Control and an involuntary employment action 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 SBUs share 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 of Fortis stock (each a “Common Share”). Such “dividend equivalent” shall be equal to
a fraction where the numerator is the product of (a) the number of 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, converted to U.S. dollars based on the Award Conversion Rate.
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
of Fortis Inc. stock or cash payment. If the grantee does not satisfy their share holding requirement stated in the
Stock Ownership Policy, 50% of the SBU awards must settle in common shares of Fortis Inc. stock.
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Outstanding Equity Awards at Fiscal Year-End
The following table provides information with respect to SBUs and PBUs that have not vested as of the end
of 2022 held by the NEOs. For presentation purposes, fractional units have been rounded to the nearest whole
unit.
Name
(a)
Linda H. Apsey
Gretchen L. Holloway
Jon E. Jipping
Christine Mason Soneral
Krista Tanner
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)
(b)
(c)
(d)
(e)
18,281 (2)
$
60,692 (3)
18,355 (4)
15,527 (6)
6,239 (2)
20,711 (3)
6,294 (4)
5,302 (6)
9,187 (2)
30,498 (3)
9,134 (4)
7,621 (6)
6,177 (2)
20,508 (3)
6,112 (4)
5,149 (6)
5,326 (2)
17,680 (3)
5,425 (4)
4,660 (6)
731,990
2,430,105
734,943
621,684
249,792
829,288
251,997
212,307
367,843
1,221,141
365,723
305,128
247,342
821,121
244,713
206,169
213,246
707,902
217,230
186,599
$
—
—
73,427 (5)
62,104 (7)
—
—
25,177 (5)
21,209 (7)
—
—
36,540 (5)
30,480 (7)
—
—
24,449 (5)
20,595 (7)
—
—
21,704 (5)
18,640 (7)
—
—
2,940,006
2,486,635
—
—
1,008,101
849,211
—
—
1,463,057
1,220,423
—
—
978,938
824,613
—
—
869,016
746,331
____________________________
(1) Value was determined by multiplying the number of units that have not vested by the closing price of Fortis
common stock on the NYSE as of December 30, 2022 ($40.04).
(2) These unvested SBUs were granted in 2020 and generally vest on January 1, 2023. These SBU numbers
include the original SBU grant plus dividend equivalent units earned.
(3) These unvested PBUs were granted in 2020 and earned with respect to the applicable performance
measures during the three-year performance period started January 1, 2020 and ended December 31,
2022. These PBU numbers include the original grant plus dividend equivalent units earned. Such PBUs
vested on January 1, 2023, and the Committee certified the achievement of 166% of the applicable
performance goals on January 30, 2023.
(4) These unvested SBUs were granted in 2021 and generally vest on January 1, 2024. These SBU numbers
include the original SBU grant plus dividend equivalent units earned.
(5) These unvested PBUs were granted in 2021 and generally vest on January 1, 2024. 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.
(6) These unvested SBUs were granted in 2022 and generally vest on January 1, 2025. These SBU numbers
include the original SBU grant plus dividend equivalent units earned.
(7) These unvested PBUs were granted in 2022 and generally vest on January 1, 2025. These PBU numbers
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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.
The PBU grants made to NEOs were made pursuant to the Executive Omnibus Plan and the SBU grants
made to NEOs were made pursuant to the Fortis Inc. 2020 Restricted Share Unit Plan. The terms of the grants
are described above in the narrative discussion accompanying the “Grants of Plan-Based Awards” Table.
Stock Vested
As previously disclosed, beginning in 2020 the standard vesting date for awards of SBUs and PBUs changed
from December 31 to January 1. Consequently, no SBUs or PBUs vested during 2022. See “Outstanding Equity
Awards at Fiscal Year-End” for information with respect to SBUs and PBUs that have a vesting date of January
1, 2023 or later.
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
(a)
Linda H. Apsey
Gretchen L. Holloway
Jon E. Jipping
Christine Mason Soneral
Krista Tanner
Plan Name
(b)
Cash Balance Component
ESRP Shift
Total Qualified Plan
ESRP
Cash Balance Component
Total Qualified Plan
ESRP
Traditional Component
Total Qualified Plan
ESRP
Cash Balance Component
Total Qualified Plan
ESRP
Cash Balance Component
Total Qualified Plan
ESRP
Number of Years
Credited Service
(#)(1)
(c)
Present Value of
Accumulated
Benefit ($)(2)
(d)
Payments During
Last Fiscal Year
($)
(e)
28.59 $
N/A
19.83
18.95
7.91
32.03
17.92
15.29
15.28
8.14
8.14
459,255
35,400
494,655
2,271,815
294,581
294,581
491,386
1,715,730
1,715,730
1,957,574
302,215
302,215
846,318
146,230
146,230
365,690
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
____________________________
(1) Credited service is estimated as of December 31, 2022 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 and Mr. Jipping, the credited service for the cash balance and traditional components of the
Qualified Plan, respectively, 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 traditional and cash balance components 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.
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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, 2022 (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, 2022. The rate at which future
expected benefit payments were discounted in calculating present values was 5.57%, the same rate used
for fiscal year-end 2022 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 3.55% for 2023 and 4.00% 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 the traditional component of the defined benefit plan, that age is the earlier
of (1) age 58 with 30 years of service (including service with DTE Energy), or (2) age 60 with 15 years of
service. For consistency, we generally use the same assumed retirement 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. Benefits under the traditional component of
the Qualified Plan were assumed to be paid as a monthly annuity payable for the lifetime of the employee.
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 Qualified Plan and the ESRP, and pension benefits provided to the NEOs under
those plans.
Qualified Plan
There are two primary retirement benefit components of the Qualified Plan. Each NEO earns benefits from
the Company under only one of these primary components.
Because our first operating utility subsidiary was acquired from DTE Energy, a component of the Qualified
Plan bears relation to the DTE Energy Corporation Retirement Plan (the “DTE Plan”). Generally, persons who
were participants in the “traditional component” of the DTE Plan as of February 28, 2003 (the date
ITCTransmission was acquired from DTE Energy) earn benefits under the traditional component of our Qualified
Plan. All other participants earn benefits under the cash balance component. Ms. Apsey also has benefits under
the ESRP shift described below.
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.
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Traditional Component of Qualified Plan
Mr. Jipping participates in the traditional component of the Qualified Plan. The benefits are determined under
the following formula, stated as an annual single life annuity payable in equal monthly installments at the normal
retirement age of 65: 1.5% times average final compensation times credited service up to 30 years, plus 1.4%
times average final compensation times credited service in excess of 30 years. Credited service includes
service with DTE Energy. Although benefits under the formula are defined in terms of a single life annuity, other
annuity forms (e.g., joint and survivor benefits) are available that have the same actuarial value as the single life
annuity benefit. The benefits are not payable in the form of a lump sum.
Average final compensation is equal to one-fifth of the NEO’s salary (excluding any bonuses or special pay)
during the 260 weeks of credited service, not necessarily consecutive, at any time during the NEO’s
employment that results in the highest average.
Benefits provided under the Qualified Plan are based on compensation up to a compensation limit under the
Internal Revenue Code (which was $305,000 in 2022 and is indexed in future years). In addition, benefits
provided under the Qualified Plan may not exceed a benefit limit under the Internal Revenue Code (which was
$245,000 payable as a single life annuity beginning at normal retirement age in 2022).
NEOs may retire with a reduced benefit as early as age 45 after 15 years of credited service. If a NEO has
30 years of credited service at retirement, the benefit that would be payable at normal retirement age is reduced
for commencement ages below 58. The percentage of the normal retirement benefit payable at sample
commencement ages is as follows:
Age 58 and older:
100%
Age 55:
Age 50:
85%
40%
If a NEO has less than 30 years but more than 15 years of credited service at retirement, the benefit that
would be payable at normal retirement age is reduced for commencement ages below age 60. The percentage
of the normal retirement benefit payable at sample commencement ages is as follows:
Age 60 and older:
100%
Age 55:
Age 50:
71%
40%
If a NEO terminates employment prior to earning 15 years of credited service, the annuity benefit may not
commence prior to attaining age 65. If the NEO terminates employment after earning 15 years of credited
service but below age 45, the benefit may commence as early as age 45. The percentage of the normal
retirement benefit payable at sample commencement ages is as follows:
Age 65 and older:
100%
Age 60:
Age 55:
Age 50:
58%
36%
23%
Mr. Jipping’s annual accrued benefit payable in monthly installments as an annuity for his lifetime, beginning
at age 60, is approximately $137,000. He is fully vested.
Cash Balance Component of Qualified Plan
Mses. Apsey, Holloway, Mason Soneral and Tanner participate in the cash balance component of the
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 same compensation limit as applied under the
traditional component of the Qualified Plan ($305,000 in 2022). Each year, a NEO’s account is also increased
by an “interest credit” based on 30-year Treasury rates.
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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 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 2022 is approximately $497,000, Ms. Holloway’s is approximately $343,000, Ms. Mason Soneral’s is
approximately $342,000, Ms. Tanner is approximately $169,000.
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 2022, although previous shifts have continued to earn interest credits. As of year-
end 2022, her ESRP shift balance was approximately $38,000.
Executive Supplemental Retirement Plan
The ESRP is a nonqualified retirement plan. Only selected executives participate, including all our NEOs.
The purpose of the ESRP is to promote the success of the Company and its subsidiaries by providing the ability
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, 2022, the ESRP account values, net of the
amounts shifted to the Qualified Plan, are as follows:
Ms. Apsey
Ms. Holloway
Mr. Jipping
Ms. Mason Soneral
Ms. Tanner
$
2,458,841
571,705
2,000,686
958,022
421,768
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.
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Nonqualified Deferred Compensation
We maintain the Executive Deferred Compensation Plan under which nonqualified deferred compensation is
permissible. Only selected officers of the Company, including the NEOs, are eligible to participate in this plan.
NEOs are allowed to defer up to 100% of their salary and bonus. Investment earnings are based on the various
investment options available under the plan and are selected by the individual NEOs. Distributions will generally
be made at the NEO’s termination of employment for any reason. Mr. Jipping elected to participate in 2021 and
his deferral was withheld in 2022. Mr. Jipping elected to defer 100% of his bonus and his deferral will be made
in 2022 due to his 2021 bonus payment occurring in 2022. The following table reports amounts contributed in
2022, together with aggregate earnings on contributions and withdrawals or distributions on contributions in
2022, under the plan.
Name (in millions of USD)
Jon E. Jipping
____________________________
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)
$
942,891 $
— $
(600,279) $
— $
3,556,819
(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, 2022. The
aggregate balance reflects a significant level of earnings on previously earned and deferred compensation.
Employment Agreements and Potential Payments Upon Termination or Change in Control
Employment Agreements
As referenced above, we entered into employment agreements with Ms. Apsey and Mr. Jipping in December
2012 which superseded the employment agreements 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. 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, 2022.
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
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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;
◦ Mr. Jipping: annual benefit under the traditional component of the Qualified Plan and vested
portion of ESRP balance; and
◦ Ms. Mason Soneral, Ms. Holloway 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, 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
for Ms. Apsey, deemed satisfaction of the eligibility requirements of our Postretirement Welfare Plan for
purposes of participation therein; and Mr. Jipping met the age and service eligibility requirements for
participation in our Postretirement Welfare Plan. 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.
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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.
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, 2022.
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)
$
— $
— $
1,730,000 $
4,312,261 $
— $
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
865,000
865,000
1,385,730
1,385,730
—
—
2,088,617
2,088,617
2,088,617
3,822,962
5,143,425
5,143,425
—
—
25,000
25,000
86,490
86,490
434,992
434,992
—
—
—
—
—
40,723
187,026
—
—
—
$
— $
— $
3,662,212 $ 12,156,052 $
8,097,042 $
8,324,791
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)
$
— $
— $
844,000 $
2,104,978 $
— $
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
422,000
422,000
676,044
676,044
—
—
714,095
714,095
714,095
1,306,315
1,757,944
1,757,944
—
—
25,000
25,000
57,195
57,195
—
—
—
—
48,150
80,319
—
—
—
—
—
—
—
—
—
—
Compensation
Cash Severance
Target Short-term Bonus
Pro Rata Short-term
(Annual) Incentive Comp
Service-Based Unit
Awards (5)
Performance-Based Unit
Awards (6)
Benefits and Outplacement
Retirement Plan
ESRP
Outplacement
Health & Welfare Benefits
Postretirement Welfare
Plan (7)
Total Payout:
Compensation
Cash Severance
Target Short-term Bonus
Pro Rata Short-term
(Annual) Incentive Comp
Service-Based Unit
Awards (5)
Performance-Based Unit
Awards (6)
Benefits and Outplacement
Retirement Plan
ESRP
Outplacement
Health & Welfare Benefits
Total Payout:
$
— $
— $
1,602,239 $
4,883,627 $
2,894,039 $
3,022,508
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Table of Contents
Compensation
Cash Severance
Target Short-term Bonus
Pro Rata Short-term
(Annual) Incentive Comp
Service-Based Unit
Awards (5)
Performance-Based Unit
Awards (6)
Benefits and Outplacement
Retirement Plan
ESRP
Outplacement
Health & Welfare Benefits
Postretirement Welfare
Plan (7)
Total Payout:
Compensation
Cash Severance
Target Short-term Bonus
Pro Rata Short-term
(Annual) Incentive Comp
Service-Based Unit
Awards (5)
Performance-Based Unit
Awards (6)
Benefits and Outplacement
Retirement Plan
ESRP
Outplacement
Health & Welfare Benefits
Jon E. Jipping - 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)
$
— $
— $
1,213,000 $
3,066,793 $
— $
—
—
—
1,038,694
2,562,880
—
—
—
—
—
—
—
—
—
—
—
—
—
—
606,500
606,500
971,613
971,613
—
—
1,038,694
1,038,694
1,038,694
1,038,694
2,562,880
2,562,880
2,562,880
2,562,880
—
—
—
—
25,000
25,000
60,652
60,652
—
—
—
—
—
43,112
—
—
—
517,169
517,169
517,169
517,169
517,169
$
4,118,743 $
517,169 $
6,389,008 $
8,242,801 $
4,725,243 $
4,251,186
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)
$
— $
— $
819,600 $
2,063,978 $
— $
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
409,800
409,800
656,500
656,500
—
—
698,224
698,224
698,224
1,284,344
1,722,897
1,722,897
—
—
25,000
25,000
86,448
86,448
—
—
—
—
39,889
111,704
—
—
—
—
—
—
Total Payout:
$
— $
— $
1,587,548 $
4,814,494 $
2,830,921 $
2,982,514
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Compensation
Cash Severance
Target Short-term Bonus
Pro Rata Short-term
(Annual) Incentive Comp
Service-Based Unit
Awards (5)
Performance-Based Unit
Awards (6)
280G Cutback
Benefits and Outplacement
Retirement Plan
ESRP
Outplacement
Health & Welfare Benefits
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)
$
— $
— $
741,800 $
1,721,533 $
— $
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
370,900
370,900
594,182
594,182
—
—
617,075
420,265
420,265
—
—
—
—
—
1,121,489
(209,490)
—
—
25,000
25,000
90,686
90,686
616,770
616,770
—
—
—
—
—
—
22,425
56,078
—
—
Total Payout:
$
— $
— $
1,451,668 $
3,960,475 $
1,407,935 $
1,486,438
____________________________
(1) All scenarios include the value of severance. For Ms. Apsey and Mr. Jipping, 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, outside of present value reductions outlined in
footnote (4), have not been included in these termination scenarios but can be found in the “Pension
Benefits Table.”
(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. Ms. Tanner 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 $209,490 (Ms.
Tanner) have been reflected.
(4) In the event of Mr. Jipping’s termination for death (pre-retirement), his spouse or designated beneficiary if
not married would receive half the 50% joint and survivor annuity under the traditional component of the
Qualified Plan. Under termination for death (pre-retirement), Ms. Apsey’s, Ms. Mason Soneral’s, Ms.
Holloway’s and Ms. Tanner’s Qualified Plan benefits are payable immediately to the surviving spouse or
designated beneficiary it not married and ESRP benefits are payable to a designated beneficiary. The
above termination scenarios do not reflect the reduction in present value of death benefits ($854,911 for Mr.
Jipping compared to present value in the Pension Benefits Table).
(5) Under the Fortis Inc. 2020 Restricted Share Unit 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. In
the case of Death, Disability or Retirement termination and 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 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 period served
from grant date to termination 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 Cause, Involuntary
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Termination Without Cause and Voluntary Termination outstanding and unvested SBU awards and
respective dividend equivalents shall be deemed to be forfeited.
(6) Under the Executive Omnibus 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 (as defined in the Executive Omnibus Plan). In the case of Death, Disability or Retirement
termination and 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 less than 15 years of service with the Company or its Affiliates, the
outstanding and unvested PBU awards and respective dividend equivalents shall be deemed to have
vested pro-rata based on the 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. Values shown in the tables above are
based on target performance for the 2021 and 2022 awards as an estimate of potential payments and
actual performance of 166% for the 2020 awards. In the case of Cause, Involuntary Termination Without
Cause and Voluntary Termination 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 involuntary termination not for cause and
change in control scenarios for Ms. Apsey since her employment agreement includes a provision for
deemed satisfaction of the eligibility requirements when terminated under these scenarios. The
Postretirement Welfare Plan benefit is included in all scenarios other than death (pre-retirement) for Mr.
Jipping since he had met the retirement eligibility terms of the plan as of December 31, 2022. It is assumed
each would commence their Postretirement Welfare Benefits at age 58. The rate at which future expected
benefit payments were discounted in calculating the Postretirement Welfare Plan present values was
5.65%, the same rate used for fiscal year-end 2022 accounting disclosure of the Postretirement Welfare
Plan.
Upon death or disability, a NEO (or his or her estate) receives a pro rata portion of his or her current year
target corporate performance bonus. All balances under the cash balance and ESRP shift components of the
Qualified Plan, and the ESRP balance (vested portion only for disability), are immediately payable. If the NEO
has 10 years of service after age 45, then the NEO (and his or her spouse) is eligible for retiree medical
benefits.
Pay Ratio
As required by the Dodd-Frank Wall Street Reform and Consumer Protection Act, and the SEC under Item
402(u) of Regulation S-K, we are providing the following information about the relationship of the annual total
compensation of our employees and the annual total compensation of Linda H. Apsey our CEO:
For 2022, our last completed fiscal year:
the median of the annual total compensation of all employees of the Company (other than Ms.
Apsey), was $171,641; and
the annual total compensation of Ms. Apsey as reported in the Summary Compensation Table was
$4,563,382.
Based on this information, Ms. Apsey’s 2022 annual total compensation was estimated to be 27 times the
median annual total compensation for all employees, other than Ms. Apsey.
We determined that, as of December 31, 2020, our employee population consisted of 698 individuals with all
of those individuals located in the United States. To identify the “median employee” from our employee
population, excluding Ms. Apsey, we utilized a consistently applied compensation measure that included the
sum of each employee’s 2020 annualized base salary as of December 31, 2020 as reflected in our payroll
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records, and target 2020 awards made under our annual corporate performance plan, 2017 Omnibus Plan,
Executive Omnibus Plan and Fortis Inc. 2020 Restricted Share Unit Plan that were not paid in 2020. We
arrayed these values to select our “median employee.”
Under Item 402(u), a company is permitted to identify its “median employee” once every three years if there
has been no significant change to its employee population or employee compensation arrangements that would
result in a significant change to its pay ratio disclosure. We updated our “median employee” for 2020 as it had
been three years since we had last identified the “median employee” for this analysis. The same median
employee was used to calculate the 2022 pay ratio.
Using our “median employee” and Ms. Apsey, we calculated the applicable Summary Compensation Table
values for each according to applicable SEC rules.
Director Compensation
The following table provides information concerning the compensation of each person who served as a non-
employee director of the Company during 2022.
Non-Employee Director Compensation Table
Name
(a)
Leanne M. Bell (2)
Robert A. Elliott
Albert Ernst (3)
Debora Frodl
Ronnie Hawkins, Jr.
David G. Hutchens
James P. Laurito
Jocelyn H. Perry (2)
Sandra E. Pierce
Kevin L. Prust
A. Douglas Rothwell
Fees Earned or
Paid in Cash ($) (1)
(b)
132,916 $
165,000
12,888
145,000
145,000
145,000
145,000
145,000
200,000
145,000
165,000
Total ($)
(h)
132,916
165,000
12,888
145,000
145,000
145,000
145,000
145,000
200,000
145,000
165,000
____________________________
(1) Includes annual Board retainer and committee chairmanship retainer, as well as a chairperson fee (for Ms.
Pierce only).
(2) Ms. Perry joined the Board in January 2022 and Ms. Bell joined the Board in February 2022.
(3) Mr. Ernst left the Board in February 2022.
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 $145,000. In addition, we pay an additional cash
retainer of $20,000 annually to the chair of each Board committee and $55,000 annually to our chairperson. We
do not pay per-meeting fees under the policy. Non-employee directors are reimbursed for their out-of-pocket
expenses incurred for the performance of their duties as directors.
We maintain a Director Deferred Compensation Plan under which nonqualified deferred compensation is
permissible. Only non-employee directors of the Company are eligible to participate in this plan. Directors are
allowed to defer up to 100% of their annual board compensation. Investment earnings are based on the various
investment options available under the plan and are selected by the individual directors. Distributions will be
made when the director ceases to serve on the Board and/or ceases to provide other non-employee consulting
services to the Company or any Fortis entity. None of the directors participated in this plan in 2022.
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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, 2023, 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, 2023 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
Gretchen L. Holloway
Jon E. Jipping
Christine Mason Soneral
Krista Tanner
Leanne M. Bell
Robert A. Elliott
Debora Frodl
Ronnie Hawkins
David G. Hutchens
James P. Laurito
Jocelyn H. Perry
Sandra E. Pierce
Kevin L. Prust
A. Douglas Rothwell
All current directors and executive officers as a group (15 persons)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
53,889
8,897
20,000
—
3,524
—
—
—
—
102,923
48,595
226,548
—
500
—
— %
464,876
* 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, 2022, there were no securities authorized for issuance under any compensation plans of
ITC Holdings.
ITEM 13.
INDEPENDENCE.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
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
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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., 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 serves 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.
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ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.
The following table provides a summary of the aggregate fees incurred for Deloitte’s services in 2022 and
2021:
Audit fees (1)
Audit-related fees (2)
Tax fees (3)
All other fees (4)
Total fees
2022
2021
2,222,000 $
2,083,000
176,000
23,000
13,000
57,000
13,000
7,000
2,434,000 $
2,160,000
$
$
____________________________
(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 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 2022 pursuant to the
pre-approval policy.
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PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.
(a)
(1) Financial Statements:
Management’s Report on Internal Control over Financial Reporting
Report of Independent Registered Public Accounting Firm
Consolidated Statements of Financial Position as of December 31, 2022 and 2021
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2022, 2021 and 2020
Consolidated Statements of Changes in Stockholder's Equity for the Years Ended December 31, 2022, 2021
and 2020
Consolidated Statements of Cash Flows for the Years Ended December 31, 2022, 2021 and 2020
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
3.1
3.2
4.3
4.5
4.6
4.7
4.8
4.9
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)
Restated Articles of Incorporation of ITC Holdings Corp. (filed with Registrant’s Form 10-Q for the
quarter ended September 30, 2016)
Tenth Amended and Restated Bylaws of ITC Holdings Corp. (filed with Registrant’s Form 8-K on
February 4, 2022)
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)
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)
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)
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)
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)
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)
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4.12
4.14
4.17
4.18
4.19
4.20
4.24
4.25
4.26
4.27
4.28
4.29
4.30
4.31
4.32
4.33
4.34
4.35
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)
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)
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)
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)
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)
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)
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)
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)
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)
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)
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)
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)
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)
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)
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)
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)
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)
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)
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4.36
4.38
4.39
4.40
4.41
4.42
4.43
4.44
4.45
4.46
4.47
4.48
4.49
4.50
4.51
4.52
4.53
4.54
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)
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)
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)
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)
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)
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)
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)
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)
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)
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)
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)
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)
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)
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)
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)
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).
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).
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).
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4.55
4.56
4.57
4.58
*10.27
10.51
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)
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)
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)
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)
Deferred Compensation Plan (filed with Registrant’s Registration Statement on Form S-1, as amended,
Reg. No. 333-123657)
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
*10.173
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)
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)
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10.184
10.185
10.186
10.187
10.188
ITC Holdings Revolving Credit Agreement, dated as of October 23, 2017, among ITC Holdings Corp.,
with the banks, financial institutions and other institutional lenders listed on the respective signature
pages thereof, JPMorgan Chase Bank, N.A., as administrative agent for the Lenders, JPMorgan Chase
Bank, N.A., Barclays Bank PLC, Wells Fargo Securities, LLC, The Bank of Nova Scotia and Mizuho
Bank, Ltd., as joint lead arrangers and joint bookrunners, Barclays Bank PLC and Wells Fargo Bank,
National Association, as co-syndication agents and The Bank of Nova Scotia and Mizuho Bank, Ltd. as
co-documentation agents (filed with Registrant’s Form 8-K on October 23, 2017)
ITCTransmission Revolving Credit Agreement, dated as of October 23, 2017, among International
Transmission Company, with the banks, financial institutions and other institutional lenders listed on the
respective signature pages thereof, JPMorgan Chase Bank, N.A., as administrative agent for the
Lenders, JPMorgan Chase Bank, N.A., Barclays Bank PLC, Wells Fargo Securities, LLC, The Bank of
Nova Scotia and Mizuho Bank, Ltd., as joint lead arrangers and joint bookrunners, Barclays Bank PLC
and Wells Fargo Bank, National Association, as co-syndication agents and The Bank of Nova Scotia
and Mizuho Bank, Ltd. as co-documentation agents (filed with Registrant’s Form 8-K on October 23,
2017)
METC Revolving Credit Agreement, dated as of October 23, 2017, among Michigan Electric
Transmission Company, LLC, with the banks, financial institutions and other institutional lenders listed
on the respective signature pages thereof, JPMorgan Chase Bank, N.A., as administrative agent for the
Lenders, JPMorgan Chase Bank, N.A., Barclays Bank PLC, Wells Fargo Securities, LLC, The Bank of
Nova Scotia and Mizuho Bank, Ltd., as joint lead arrangers and joint bookrunners, Barclays Bank PLC
and Wells Fargo Bank, National Association, as co-syndication agents and The Bank of Nova Scotia
and Mizuho Bank, Ltd. as co-documentation agents (filed with Registrant’s Form 8-K on October 23,
2017)
ITC Midwest Revolving Credit Agreement, dated as of October 23, 2017, among ITC Midwest LLC, with
the banks, financial institutions and other institutional lenders listed on the respective signature pages
thereof, JPMorgan Chase Bank, N.A., as administrative agent for the Lenders, JPMorgan Chase Bank,
N.A., Barclays Bank PLC, Wells Fargo Securities, LLC, The Bank of Nova Scotia and Mizuho Bank,
Ltd., as joint lead arrangers and joint bookrunners, Barclays Bank PLC and Wells Fargo Bank, National
Association, as co-syndication agents and The Bank of Nova Scotia and Mizuho Bank, Ltd. as co-
documentation agents (filed with Registrant’s Form 8-K on October 23, 2017)
ITC Great Plains Revolving Credit Agreement, dated as of October 23, 2017, among ITC Great Plains,
LLC, with the banks, financial institutions and other institutional lenders listed on the respective
signature pages thereof, JPMorgan Chase Bank, N.A., as administrative agent for the Lenders,
JPMorgan Chase Bank, N.A., Barclays Bank PLC, Wells Fargo Securities, LLC, The Bank of Nova
Scotia and Mizuho Bank, Ltd., as joint lead arrangers and joint bookrunners, Barclays Bank PLC and
Wells Fargo Bank, National Association, as co-syndication agents and The Bank of Nova Scotia and
Mizuho Bank, Ltd. as co-documentation agents (filed with Registrant’s Form 8-K on October 23, 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
10.194
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)
ITC Holdings Amendment and Restatement Agreement dated as of January 10, 2020, among ITC
Holdings Corp., the banks, financial institutions and other institutional lenders listed on the respective
signature pages thereof, Wells Fargo Bank, National Association, in its capacity as successor
administrative agent and JPMorgan Chase Bank, N.A., in its capacity as resigning administrative agent,
amending and restating as of January 10, 2020 in the form attached as Exhibit A thereto the Revolving
Credit Agreement, dated as of October 23, 2017, among ITC Holdings Corp., the banks, financial
institutions and other institutional party thereto, JPMorgan Chase Bank, N.A., as administrative agent
for the lenders, JPMorgan Chase Bank, N.A., Barclays Bank PLC, Wells Fargo Securities, LLC, The
Bank of Nova Scotia and Mizuho Bank, Ltd., as joint lead arrangers and joint bookrunners, Barclays
Bank PLC and Wells Fargo Bank, National Association, as co-syndication agents and The Bank of
Nova Scotia and Mizuho Bank, Ltd. as co-documentation agents (filed with Registrant’s Form 8-K on
January 10, 2020)
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10.195
10.196
10.197
10.198
*10.200
*10.201
*10.202
*10.203
ITCTransmission Amendment and Restatement Agreement dated as of January 10, 2020, among
International Transmission Company, the banks, financial institutions and other institutional lenders
listed on the respective signature pages thereof, Wells Fargo Bank, National Association, in its capacity
as successor administrative agent and JPMorgan Chase Bank, N.A., in its capacity as resigning
administrative agent, amending and restating as of January 10, 2020 in the form attached as Exhibit A
thereto the Revolving Credit Agreement, dated as of October 23, 2017, among International
Transmission Company, the banks, financial institutions and other institutional party thereto, JPMorgan
Chase Bank, N.A., as administrative agent for the lenders, JPMorgan Chase Bank, N.A., Barclays Bank
PLC, Wells Fargo Securities, LLC, The Bank of Nova Scotia and Mizuho Bank, Ltd., as joint lead
arrangers and joint bookrunners, Barclays Bank PLC and Wells Fargo Bank, National Association, as
co-syndication agents and The Bank of Nova Scotia and Mizuho Bank, Ltd. as co-documentation
agents (filed with Registrant’s Form 8-K on January 10, 2020)
METC Amendment and Restatement Agreement dated as of January 10, 2020, among Michigan
Electric Transmission Company, LLC, the banks, financial institutions and other institutional lenders
listed on the respective signature pages thereof, Wells Fargo Bank, National Association, in its capacity
as successor administrative agent and JPMorgan Chase Bank, N.A., in its capacity as resigning
administrative agent, amending and restating as of January 10, 2020 in the form attached as Exhibit A
thereto the Revolving Credit Agreement, dated as of October 23, 2017, among Michigan Electric
Transmission Company, LLC, the banks, financial institutions and other institutional party thereto,
JPMorgan Chase Bank, N.A., as administrative agent for the lenders, JPMorgan Chase Bank, N.A.,
Barclays Bank PLC, Wells Fargo Securities, LLC, The Bank of Nova Scotia and Mizuho Bank, Ltd., as
joint lead arrangers and joint bookrunners, Barclays Bank PLC and Wells Fargo Bank, National
Association, as co-syndication agents and The Bank of Nova Scotia and Mizuho Bank, Ltd. as co-
documentation agents (filed with Registrant’s Form 8-K on January 10, 2020)
ITC Midwest Amendment and Restatement Agreement dated as of January 10, 2020, among ITC
Midwest LLC, the banks, financial institutions and other institutional lenders listed on the respective
signature pages thereof, Wells Fargo Bank, National Association, in its capacity as successor
administrative agent and JPMorgan Chase Bank, N.A., in its capacity as resigning administrative agent,
amending and restating as of January 10, 2020 in the form attached as Exhibit A thereto the Revolving
Credit Agreement, dated as of October 23, 2017, among ITC Midwest LLC, the banks, financial
institutions and other institutional party thereto, JPMorgan Chase Bank, N.A., as administrative agent
for the lenders, JPMorgan Chase Bank, N.A., Barclays Bank PLC, Wells Fargo Securities, LLC, The
Bank of Nova Scotia and Mizuho Bank, Ltd., as joint lead arrangers and joint bookrunners, Barclays
Bank PLC and Wells Fargo Bank, National Association, as co-syndication agents and The Bank of
Nova Scotia and Mizuho Bank, Ltd. as co-documentation agents (filed with Registrant’s Form 8-K on
January 10, 2020)
ITC Great Plains Amendment and Restatement Agreement dated as of January 10, 2020, among ITC
Great Plains, LLC, the banks, financial institutions and other institutional lenders listed on the respective
signature pages thereof, Wells Fargo Bank, National Association, in its capacity as successor
administrative agent and JPMorgan Chase Bank, N.A., in its capacity as resigning administrative agent,
amending and restating as of January 10, 2020 in the form attached as Exhibit A thereto the Revolving
Credit Agreement, dated as of October 23, 2017, among ITC Great Plains, LLC, the banks, financial
institutions and other institutional party thereto, JPMorgan Chase Bank, N.A., as administrative agent
for the lenders, JPMorgan Chase Bank, N.A., Barclays Bank PLC, Wells Fargo Securities, LLC, The
Bank of Nova Scotia and Mizuho Bank, Ltd., as joint lead arrangers and joint bookrunners, Barclays
Bank PLC and Wells Fargo Bank, National Association, as co-syndication agents and The Bank of
Nova Scotia and Mizuho Bank, Ltd. as co-documentation agents (filed with Registrant’s Form 8-K on
January 10, 2020)
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)
Executive Omnibus Plan, effective February 4, 2020. (filed with Registrant’s Form 10-K for the year
ended December 31, 2019)
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)
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)
121
Table of Contents
10.207
10.208
10.209
10.210
10.211
*10.212
*10.213
*10.214
Amendment No. 1 to Credit Agreement, dated as of May 17, 2021, among ITC Holdings Corp., with the
banks, financial institutions and other institutional lenders listed on the respective signature pages
thereof, and Wells Fargo Bank, National Association, in its capacity as administrative agent (filed with
Registrant’s Form 8-K on May 17, 2021)
Amendment No. 1 to Credit Agreement, dated as of May 17, 2021, among International Transmission
Company, with the banks, financial institutions and other institutional lenders listed on the respective
signature pages thereof, and Wells Fargo Bank, National Association, in its capacity as administrative
agent (filed with Registrant’s Form 8-K on May 17, 2021)
Amendment No. 1 to Credit Agreement, dated as of May 17, 2021, among Michigan Electric
Transmission Company, LLC, with the banks, financial institutions and other institutional lenders listed
on the respective signature pages thereof, and Wells Fargo Bank, National Association, in its capacity
as administrative agent (filed with Registrant’s Form 8-K on May 17, 2021)
Amendment No. 1 to Credit Agreement, dated as of May 17, 2021, among ITC Midwest LLC, with the
banks, financial institutions and other institutional lenders listed on the respective signature pages
thereof, and Wells Fargo Bank, National Association, in its capacity as administrative agent (filed with
Registrant’s Form 8-K on May 17, 2021)
Amendment No. 1 to Credit Agreement, dated as of May 17, 2021, among ITC Great Plains, LLC, with
the banks, financial institutions and other institutional lenders listed on the respective signature pages
thereof, and Wells Fargo Bank, National Association, in its capacity as administrative agent (filed with
Registrant’s Form 8-K on May 17, 2021)
Executive Omnibus Plan, as amended November 11, 2021 (filed with Registrant’s Form 10-K for the
year ended December 31, 2021)
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)
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)
**21
List of Subsidiaries
**31.1
**31.2
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
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,
2021 (formatted in Inline XBRL and contained in Exhibit 101)
___________________________
*
**
***
Management contract or compensatory plan or arrangement
Filed herewith
Management contract or compensatory plan or arrangement filed herewith
122
Table of Contents
SCHEDULE I — Condensed Financial Information of Registrant
ITC HOLDINGS CORP.
CONDENSED STATEMENTS OF FINANCIAL POSITION (PARENT COMPANY ONLY)
December 31,
2022
2021
(In millions of USD, except share data)
ASSETS
Current assets
Cash and cash equivalents
Accounts receivable from subsidiaries
Intercompany tax receivable from subsidiaries
Advances to subsidiaries
Prepaid and other current assets
Total current assets
Other assets
Investment in subsidiaries
Deferred income taxes
Advances to subsidiaries
Other assets
Total other assets
TOTAL ASSETS
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities
Accrued compensation
Accrued interest
Debt maturing within one year
Other current liabilities
Total current liabilities
Accrued pension and postretirement liabilities
Other liabilities
Long-term debt (net of deferred financing fees and discount of $19 and $17, respectively)
TOTAL LIABILITIES
STOCKHOLDER’S EQUITY
Common stock, without par value, 235,000,000 shares authorized, 224,203,112 shares issued and
outstanding at December 31, 2022 and 2021
Retained earnings
Accumulated other comprehensive income (loss)
Total stockholder’s equity
$
2 $
$
$
18
26
—
1
47
6,124
90
4
113
6,331
6,378 $
59 $
30
384
12
485
41
89
3,091
3,706
892
1,753
27
2,672
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY
$
6,378 $
See notes to condensed financial statements (parent company only).
123
3
20
16
50
3
92
5,784
142
4
112
6,042
6,134
72
23
654
8
757
52
78
2,773
3,660
892
1,584
(2)
2,474
6,134
Table of Contents
SCHEDULE I — Condensed Financial Information of Registrant
ITC HOLDINGS CORP.
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (PARENT COMPANY ONLY)
(In millions of USD)
Other (expense) income, net
General and administrative expense
Taxes other than income taxes
Interest expense
LOSS BEFORE INCOME TAXES
INCOME TAX BENEFIT
LOSS AFTER TAXES
EQUITY IN SUBSIDIARIES’ NET EARNINGS
NET INCOME
OTHER COMPREHENSIVE INCOME (LOSS)
Derivative instruments (net of tax of $12 for the year ended December 31, 2022, $2
for the year ended December 31, 2021, $7 for the year ended December 31, 2020)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Year Ended December 31,
2022
2021
2020
$
(5) $
3 $
(8)
—
(135)
(148)
(35)
(113)
555
442
29
29
(30)
(2)
(129)
(158)
(46)
(112)
518
406
6
6
TOTAL COMPREHENSIVE INCOME
$
471 $
412 $
See notes to condensed financial statements (parent company only).
5
(20)
(1)
(122)
(138)
(43)
(95)
502
407
(15)
(15)
392
124
Table of Contents
SCHEDULE I — Condensed Financial Information of Registrant
ITC HOLDINGS CORP.
CONDENSED STATEMENTS OF CASH FLOWS (PARENT COMPANY ONLY)
(In millions of USD)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income
Adjustments to reconcile net income to net cash used in operating activities:
Equity in subsidiaries' earnings
Dividends from subsidiaries
Deferred and other income taxes
Net intercompany tax payments from subsidiaries
Share-based compensation
Other
Changes in assets and liabilities, exclusive of changes shown separately:
Accounts receivable from subsidiaries
Intercompany tax receivable from subsidiaries
Accrued compensation
Other current and non-current assets and liabilities, net
Net cash provided by (used in) operating activities
CASH FLOWS FROM INVESTING ACTIVITIES
Equity contributions to subsidiaries
Return of capital from subsidiaries
Advances to subsidiaries
Proceeds from repayment of advances to subsidiaries
Other
Net cash provided by investing activities
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt
Borrowings under revolving credit agreement
Borrowings under term loan credit agreements
Net (repayment) issuance of commercial paper
Repayment of long-term debt
Repayments of revolving credit agreement
Repayments of term loan credit agreement
Dividends to ITC Investment Holdings
Other
Net cash provided by (used in) financing activities
NET INCREASE IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH
CASH, CASH EQUIVALENTS AND RESTRICTED CASH — Beginning of period
Year Ended December 31,
2022
2021
2020
$
442 $
406 $
407
(555)
88
(41)
82
3
50
2
(10)
(13)
2
50
(58)
185
—
50
2
179
600
89
—
(21)
(500)
(118)
—
(273)
(6)
(229)
—
3
(518)
10
(41)
56
25
4
(2)
(9)
4
(2)
(67)
(51)
259
—
—
1
209
—
93
—
88
—
(91)
—
(232)
1
(141)
1
2
(502)
3
(46)
33
15
2
9
(4)
(12)
(3)
(98)
(88)
228
(50)
—
(2)
88
700
293
200
(133)
—
(290)
(400)
(330)
(30)
10
—
2
2
CASH, CASH EQUIVALENTS AND RESTRICTED CASH — End of period
$
3 $
3 $
See notes to condensed financial statements (parent company only).
125
Table of Contents
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 and term loan term credit agreements. 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, 2022 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
“Investments 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, 2022, the maturities of our debt outstanding were as follows:
(In millions of USD)
2023
2024
2025
2026
2027
2028 and thereafter
Total
$
$
384
410
—
400
1,100
1,200
3,494
Refer to Note 8 to the consolidated financial statements for additional information on the ITC Holdings Senior
Notes, the ITC Holdings Revolving Credit Agreements, 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 Senior Notes
was $3,132 million and $3,516 million at December 31, 2022 and 2021, respectively. The total book value of the
ITC Holdings Senior Notes, net of discount and deferred financing fees, was $3,331 million and $3,233 million
at December 31, 2022 and 2021, respectively. The fair values of the ITC Holdings Senior Notes represent Level
2 under the three-tier hierarchy described in Note 11 to the consolidated financial statements.
Revolving Credit Agreements
At December 31, 2022 and 2021, we had $10 million and $39 million, respectively, outstanding under our
revolving credit agreements, which are variable rate loans. The fair value of these loans approximates book
value based on the borrowing rates currently available for variable rate loans obtained from third party lending
institutions. The fair values of the revolving credit agreements represent Level 2 under the three-tier hierarchy
described in Note 11 to the consolidated financial statements.
126
Table of Contents
Other Financial Instruments
The carrying value of other financial instruments included in current assets and current liabilities, including
cash and cash equivalents, special deposits and commercial paper, approximates their fair value due to the
short-term nature of these instruments.
3. RELATED-PARTY TRANSACTIONS
Net Intercompany Receivables and Payables
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.
Retirement Benefits
We are the plan sponsor for a pension plan, other postretirement plans and a defined contribution plan. The
benefits-related expenses recorded by our affiliates 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.
Equity Transactions
(In millions of USD)
Equity contributions to subsidiaries
Dividends from subsidiaries
Return of capital from subsidiaries
Intercompany Tax Sharing Arrangement
Year Ended December 31,
2022
2021
2020
$
(58) $
(51) $
88
185
10
259
(88)
3
228
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.
(In millions of USD)
Net income tax payments (to) from: (a)
ITCTransmission
METC
ITC Midwest
ITC Great Plains
Other
____________________________
Year Ended December 31,
2022
2021
2020
$
25 $
24 $
19
33
5
—
15
10
6
1
17
9
1
6
—
(a) The net income tax payments were pursuant to intercompany tax sharing arrangements, and the total of
these tax payments is presented as a net cash outflow or inflow from operating activities in the condensed
parent company 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. Additionally, ITC Holdings paid its subsidiaries for
NOLs utilized by the consolidated group.
Intercompany Loan Agreement
On September 21, 2020, we advanced an intercompany loan to ITCTransmission totaling $50 million, due
September 21, 2022. On January 14, 2022, ITCTransmission repaid the intercompany loan in full with proceeds
127
Table of Contents
from the issuance of First Mortgage Bonds on January 14, 2022. We received interest payments of less than
$1 million, $1 million and less than $1 million during the years ended December 31, 2022, 2021 and 2020,
respectively, from ITCTransmission associated with this intercompany loan. Additionally, at December 31, 2022
we had a $4 million intercompany loan with a subsidiary, due June 1, 2046. We received principal and interest
payments of less than $1 million for the year ended December 31, 2022, and $1 million for each of the years
ended December 31, 2021 and 2020, from the subsidiary associated with this intercompany loan.
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:
(In millions of USD)
Cash and cash equivalents
Restricted cash included in:
Other non-current assets
Total cash, cash equivalents and restricted cash
Supplementary Cash Flows Information
(In millions of USD)
Supplementary cash flows information:
Interest paid
Income taxes paid
Income tax refunds received
ITEM 16. FORM 10-K SUMMARY.
Not applicable.
December 31,
2022
2021
2020
2019
2 $
3 $
2 $
1
3 $
—
3 $
—
2 $
2
—
2
$
$
Year Ended December 31,
2022
2021
2020
$
121 $
11
—
119 $
—
—
116
2
2
128
Table of Contents
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 9, 2023.
SIGNATURES
ITC HOLDINGS CORP.
By:
/s/ LINDA H. APSEY
Linda H. Apsey
President and 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
Linda H. Apsey
President and Chief Executive
Officer (principal executive officer)
February 9, 2023
/s/ GRETCHEN L. HOLLOWAY
Gretchen L. Holloway
Senior Vice President and Chief Financial Officer
(principal financial and accounting officer)
February 9, 2023
/s/ SANDRA E. PIERCE
Sandra E. Pierce
/s/ ROBERT A. ELLIOTT
Robert A. Elliott
/s/ LEANNE M. BELL
Leanne M. Bell
/s/ DEBORA FRODL
Debora Frodl
/s/ RONNIE D. HAWKINS, JR
Ronnie D. Hawkins, Jr
/s/ DAVID G. HUTCHENS
David G. Hutchens
/s/ JAMES P. LAURITO
James P. Laurito
/s/ JOCELYN H. PERRY
Jocelyn H. Perry
/s/ KEVIN L. PRUST
Kevin L. Prust
/s/ A. DOUGLAS ROTHWELL
A. Douglas Rothwell
Director and Chairman
February 9, 2023
February 9, 2023
February 9, 2023
February 9, 2023
February 9, 2023
February 9, 2023
February 9, 2023
February 9, 2023
February 9, 2023
February 9, 2023
Director
Director
Director
Director
Director
Director
Director
Director
Director
129