ITC Annual Report 2019 | Quarterlytics

FY2019 Annual Report · ITC

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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, 2019

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

Commission File Number: 001-32576

ITC HOLDINGS CORP.

(Exact Name of Registrant as Specified in Its Charter)

Michigan

32-0058047

(State or Other Jurisdiction of Incorporation or Organization)

(I.R.S. Employer Identification No.)

27175 Energy Way
Novi, Michigan 48377
(Address Of Principal Executive Offices, Including Zip Code)
(248) 946-3000
(Registrant’s Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class
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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and
(2) has been subject to such filing requirements for the past 90 days. Yes
* (Note: the Registrant is a voluntary filer and has not
been subject to the filing requirements under Section 13 or 15(d) of the Securities Exchange Act of 1934 for the preceding 12 months.)

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

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

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller Reporting
Company

Emerging growth
company

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for

complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes

The aggregate market value of the registrant’s common stock held by non-affiliates on June 30, 2019 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 common stock, no par value, outstanding as of February 12, 2020.

None

DOCUMENTS INCORPORATED BY REFERENCE

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ITC Holdings Corp.

Form 10-K for the Fiscal Year Ended December 31, 2019

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

Selected Financial Data

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

PART III
Item 10.

Directors, Executive Officers and Corporate Governance

Item 11.

Executive Compensation

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters

Item 13.

Certain Relationships and Related Transactions, and Director Independence

Item 14.

Principal Accountant Fees and Services

PART IV
Item 15.

Exhibits and Financial Statement Schedules

Item 16.

Form 10-K Summary

Signatures

Page
7

120

121

122

123

134

135

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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 Interconnection” are references to ITC Interconnection LLC, a wholly-owned subsidiary of ITC Holdings;

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

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

Holdings;

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

MTH;

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

together;

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

subsidiary of ITC Holdings;

• “Regulated Operating Subsidiaries” are references to ITCTransmission, METC, ITC Midwest, ITC Great

Plains and ITC Interconnection 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;

• “Executive Omnibus Plan” are references to the Company’s February 4, 2020 long-term equity incentive

plan;

• “ACPB” are references to an award under the annual corporate performance bonus plan;

• “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);

• “ARAM” are references to the average rate assumption method of amortization;

• “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;

• “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;

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

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

• “Easement Agreement” are references to the Amended and Restated Easement Agreement entered into by

METC and Consumers Energy dated April 29, 2002 and as further supplemented;

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

• “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;

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

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

• “Fortis” are references to Fortis Inc.;

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

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

requirement;

• “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;

• “GIC” are references to GIC Private Limited;

• “GIAs” are references to generator interconnection agreements;

• “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;

• “ITC Investment Holdings” are references to ITC Investment Holdings Inc., a majority owned indirect

subsidiary of Fortis in which GIC has an indirect minority ownership interest;

• “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;

• “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;

• “LIBOR” are references to the London Interbank Offered Rate;

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

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• “Merger Agreement” are references to the agreement and plan of merger between Fortis, FortisUS, Element

Acquisition Sub, Inc. and ITC Holdings for the merger;

• “Mid-Kansas” are references to Mid-Kansas Electric Company LLC;

• “Mid-Kansas Agreement” are references to an Amended and Restated Maintenance Agreement entered into
by Mid-Kansas and ITC Great Plains dated as of August 24, 2010, and most recently amended effective as
of March 6, 2017;

• “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;

• “November 2018 Order” are references to an order issued by the FERC on November 15, 2018 regarding

MISO ROE Complaints;

• “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;

• “PJM” are references to PJM Interconnection LLC, a FERC-approved RTO which oversees the operation of
the bulk power transmission system for a substantial portion of the Eastern United States, and of which ITC
Interconnection is a member;

• “ROE” are references to return on equity;

• “RSGM” are references to the Reverse South Georgia Method of amortization;

• “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 Shareholders’ Agreement, dated as of October 14, 2016
by and among the Company, ITC Investment Holdings, FortisUS, Eiffel (as successor to Finn Investment

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Pte Ltd), and any other person that becomes a shareholder of ITC Investment Holdings pursuant to such
agreement;

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

• “S&P” are references to S&P Global Ratings;

• “TCJA” are references to the Tax Cuts and Jobs Act of 2017, a comprehensive tax reform bill enacted on

December 22, 2017;

• “TO” are references to transmission owner; and

• “ULCS” are references to Utility Lines Construction Services, LLC

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ITEM 1.

BUSINESS.

Overview

PART I

Our business consists primarily of the electric transmission operations of our Regulated Operating Subsidiaries.
ITC Holdings was incorporated in the State of Michigan in 2002. In 2016, ITC Holdings became a wholly-owned
subsidiary of ITC Investment Holdings. Fortis owns a majority indirect equity interest in ITC Investment Holdings,
with GIC holding an indirect equity interest of 19.9%. 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. Our business strategy is to own, operate, maintain and invest in
transmission infrastructure in order to enhance system integrity and reliability, reduce transmission constraints and
support new generating resources to interconnect to our transmission systems.

As electric transmission utilities with rates regulated by the FERC, our Regulated Operating Subsidiaries earn
revenues for the use of their electric transmission systems by our 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.”

Development of Business

We are actively identifying and investing in transmission infrastructure required to meet reliability needs and
energy policy objectives. Our long-term growth plan includes ongoing investments in our current regulated
transmission systems and the identification of incremental development projects throughout North America. 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 development opportunities in “Item 1A Risk Factors.”

We expect to invest approximately $3.7 billion from 2020 through 2024 at our Regulated Operating Subsidiaries.
Included in this amount are capital expenditures to: (1) maintain and replace our current transmission infrastructure;
(2) enhance system integrity and reliability and accommodate load growth; (3) upgrade physical and technological
grid security and (4) develop and build regional transmission infrastructure, including additional transmission
facilities that will provide interconnection opportunities for generating facilities.

Through our development activities, we pursue projects in North America that are in line with our business
strategy, enhance competitive wholesale electricity markets and facilitate interconnections of new generating
resources, including wind generation and other renewable resources necessary to achieve state and federal policy
goals. We are also actively pursuing development initiatives related to grid modernization and contracted
transmission projects.

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
Subsidaries’ 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 residential, commercial and
industrial end-use consumers. The operations performed by our Regulated Operating Subsidiaries fall into the
following categories:

• asset planning;

• engineering, design and construction;

• asset protection and performance;

• cyber security operations and engineering;

• maintenance; and

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• real time operations.

Asset Planning

The Asset Planning group uses detailed system models and load forecasts to develop our system expansion
capital plans. Expansion capital plans identify projects that address reliability issues and/or produce economic
savings for customers by eliminating constraints.

The Asset Planning group submits 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 Asset Planning
group plans 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, Design and Construction

The Engineering, Design and Construction group is responsible for design, equipment specifications,
maintenance plans and project management for capital and maintenance work. We work with outside contractors
to perform various aspects of our engineering, design and construction, but retain 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.

Asset Protection and Performance

The Asset Protection and Performance group is responsible for safety, human performance, 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 not to
compromise the safety of our employees, contractors or the public in the course of providing the most reliable
electricity transmission services.

Due to the growing trend in the theft of data, the security of hard assets including laptops, mechanical keys,
badges, etc. is critical. We have established guidelines to help maintain the security of company assets and regularly
monitor potential security threats.

Cyber Security Operations and Engineering

The Cyber Security Operations and Engineering group is responsible for protecting our digital assets and data
by deploying advanced tools, techniques and monitoring systems designed to counteract and neutralize cyber
threats.

Maintenance

We develop and track preventive maintenance plans to promote safe and reliable systems. By performing
preventive maintenance on our assets, we can minimize the need for reactive maintenance, resulting in improved
reliability. 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.

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.

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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 the electric distribution system to which ITCTransmission’s transmission system connects.
A set of three operating contracts sets forth the terms and conditions related to DTE Electric’s and ITCTransmission’s
ongoing working relationship. These contracts include the following:

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

Generator Interconnection and Operation Agreement. The GIOA established, 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.

Coordination and Interconnection Agreement. The CIA governs 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 the electric distribution system to which METC’s transmission system connects.
METC is a party to a number of operating contracts with Consumers Energy that govern the operations and
maintenance of its transmission system. These contracts include the following:

Amended and Restated Easement Agreement. Under the Easement Agreement, Consumers Energy
provides METC with an easement to the land on which a majority of METC’s transmission towers, poles, lines
and other transmission facilities used to transmit electricity for Consumers Energy and others are located. METC
pays Consumers Energy an annual rent for the easement and also pays for any rentals, property taxes and
other fees related to the property covered by the Easement Agreement.

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

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

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

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

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ITC Midwest

IP&L operates the electric distribution system to which ITC Midwest’s transmission system connects. ITC
Midwest is a party to a number of operating contracts with IP&L that govern the operations and maintenance of
its transmission system. 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
on behalf of ITC Midwest. 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. Mid-Kansas and ITC Great Plains have entered into the
Mid-Kansas Agreement pursuant to which Mid-Kansas has agreed to perform various field operations and
maintenance services related to certain ITC Great Plains assets.

ITC Interconnection

ITC Interconnection acquired certain transmission assets from a merchant generating company and placed a
345kV transmission line in service. As a result, ITC Interconnection is a TO in PJM and is subject to rate regulation
by the FERC. The revenues earned by ITC Interconnection are based on its facilities reimbursement agreement
with the merchant generating company.

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. In addition, the FERC has signaled its desire for substantial new investment
in the transmission sector by implementing various financial and other incentives.

The FERC has also issued orders to promote non-discriminatory transmission access for all transmission
customers. In the United States, electric transmission assets are predominantly owned, operated and maintained
by utilities that also own electricity generation and distribution assets, known as vertically integrated utilities. The
FERC has recognized that the vertically-integrated utility model inhibits the provision of non-discriminatory
transmission access and, in order to alleviate this potential discrimination, the FERC has mandated that all
transmission systems over which it has jurisdiction must be operated in a comparable, non-discriminatory manner
such that any seller of electricity affiliated with a TO or transmission operator is not provided with preferential
treatment. The FERC has also indicated that independent transmission companies can play a prominent role in
furthering its policy goals and has encouraged the legal and functional separation of transmission operations from
generation and distribution operations.

The FERC requires compliance with certain reliability standards by TOs 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

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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. In 1996, in order to
facilitate open access transmission for participants in wholesale power markets, the FERC issued Order No. 888.
Order No. 888 encouraged investor owned utilities to cede operational control over their transmission systems to
ISOs, which are not-for-profit entities.

As an alternative to ceding operating control of their transmission assets to ISOs, certain investor owned utilities
began to promote the formation of for-profit transmission companies, which would assume control of the operation
of the grid. In 1999, the FERC issued Order No. 2000, which strongly encouraged utilities to voluntarily transfer
operational control of their transmission systems to RTOs. RTOs, as envisioned in Order No. 2000, would assume
many of the functions of an ISO, but the FERC permitted greater flexibility with regard to the organization and
structure of RTOs than it had for ISOs. RTOs could accommodate the inclusion of independently owned, for-profit
companies that own transmission assets within their operating structure. Independent ownership would facilitate
not only the independent operation of the transmission systems, but also the formation of companies with a greater
financial interest in maintaining and augmenting the capacity and reliability of those systems. RTOs, such as MISO
and SPP, monitor electric reliability and are responsible for coordinating the operation of the wholesale electric
transmission system and ensuring fair, non-discriminatory access to the transmission grid.

In 2011, the FERC issued Order No. 1000, which amends certain existing transmission planning and cost
allocation requirements to ensure that FERC-jurisdictional services are provided at just and reasonable rates and
on a basis that is just and reasonable and not unduly discriminatory or preferential. Order No. 1000 can create
competition for certain future transmission projects, including within our current operating areas.

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, including our portions of the four MVPs in the ITC Midwest footprint and the
Thumb Loop Project in the Michigan footprint. Additionally, certain projects at ITC Great Plains are eligible for
recovery through a region-wide charge in the SPP tariff, including three regional cost sharing projects in Kansas.

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, METC and ITC Interconnection

Michigan

The Michigan Public Service Commission has jurisdiction over the siting of certain transmission facilities.
Additionally, ITCTransmission, METC and ITC Interconnection 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, METC and ITC Interconnection 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, 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 this 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 may be subject to the regulatory oversight of Oklahoma Department of Environmental Quality
for compliance with environmental standards and regulations relating to construction of proposed transmission
lines.

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 21.1%, 23.2% and 24.8%, respectively, of our consolidated billed revenues for the year ended
December 31, 2019. One or more of these customers together have consistently represented a significant
percentage of our operating revenue. These percentages of total billed revenues of DTE Electric, Consumers
Energy and IP&L include the collection of 2017 revenue accruals and deferrals and exclude any amounts for the
2019 revenue accruals and deferrals that were included in our 2019 operating revenues, but will not be billed to
our customers until 2021. 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

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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. However, due to the implementation of the FERC
Order No. 1000, 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. See further discussion of Order No. 1000 above under “Regulatory Environment —
Federal Regulation.”

Employees

As of December 31, 2019, we had 707 employees. We consider our relations with our employees to be good.

Environmental Matters

See “Environmental Matters” in Note 19 to the consolidated financial statements.

Available Information Under the Securities Exchange Act of 1934

Our Internet address is http://www.itc-holdings.com. Visit our website to learn more about us. Financial and
other material information regarding us is routinely posted on our website and is readily accessible. 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 and the approved capital structures, 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

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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.

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 expect to incur expenses related to the pursuit of development
opportunities, which may be higher than forecasted.

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

Any capital investment at our Regulated Operating Subsidiaries may be lower than our published estimates

due to, among other factors, the impact of:

•

actual or forecasted loads;

regional economic conditions;

• weather conditions;

•

union strikes or labor shortages;

• material and equipment prices and availability;

•

variances between estimated and actual costs of construction contracts awarded;

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

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 expect to incur expenses to pursue strategic development 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

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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
consolidated results of operations, cash flows and financial condition.

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, SPP or PJM. 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.

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

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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
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

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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 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.

Acts of war, terrorist attacks, natural disasters, severe weather 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, natural disasters, severe weather 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. 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 and terrorist attacks, as well as natural disasters, severe weather 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.

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.

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Changes in tax laws or regulations may negatively affect our results of operations, net income, financial
condition, 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. We cannot predict the timing
or impacts of any future modifications or changes in tax laws. Changes in federal, state or local tax rates or other
aspects of tax laws could materially and adversely affect our results of operations, net income, financial condition,
cash flows, and credit metrics.

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.

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• 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, cash flows and results of operations.

We may incur substantial additional indebtedness in the future. The incurrence of additional indebtedness would

increase the leverage-related risks described above.

Adverse changes in our credit ratings may negatively affect us.

Our ability to access capital markets is important to our ability to operate our business. Increased scrutiny of
the energy industry and the impact of regulation, as well as changes in our financial performance and unfavorable
conditions in the capital markets could result in credit agencies reexamining and downgrading our credit ratings.
In addition, because we are a subsidiary of Fortis, a downgrade in Fortis’ credit rating could cause our credit rating
to be downgraded as well, even if our creditworthiness has not otherwise deteriorated. A downgrade in our credit
ratings could restrict or discontinue our ability to access capital markets at attractive rates and increase our borrowing
costs. A rating downgrade could also increase the interest we pay on commercial paper and under 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 17 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 15,900 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 approximately 660 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;

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• 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.

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

Our Regulated Operating Subsidiaries have issued certain 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 11 to the consolidated
financial statements for more information on the outstanding debt of our Regulated Operating Subsidiaries. As of
December 31, 2019, there were no liens or encumbrances on the assets of ITC Interconnection.

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, 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 6 and 19 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.

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 $250 million and $200 million to our parent, ITC Investment Holdings, during the
years ended December 31, 2019 and 2018, respectively. ITC Holdings also paid dividends of $83 million to ITC
Investment Holdings in January 2020. 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.

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ITEM 6.

SELECTED FINANCIAL DATA.

The selected historical financial data presented below should be read together with our consolidated financial
statements and the notes to those statements and “Item 7 Management’s Discussion and Analysis of Financial
Condition and Results of Operations,” included elsewhere in this Form 10-K.

(In millions)

2019

2018

2017

2016

2015

OPERATING REVENUES (a) (b)

Transmission and other services

1,286

1,192

1,226

1,142

1,025

ITC Holdings and Subsidiaries

Year Ended December 31,

Formula Rate true-up

Total operating revenues

OPERATING EXPENSES

Operation and maintenance

General and administrative (c) (d)

Depreciation and amortization

Taxes other than income taxes

Other operating (income) and expense, net

Total operating expenses (d)

OPERATING INCOME (d)

OTHER EXPENSES (INCOME)

Interest expense, net

Allowance for equity funds used during
construction

Other (income) and expenses, net (d)

Total other expenses (income) (d)

INCOME BEFORE INCOME TAXES

INCOME TAX PROVISION (e)

NET INCOME

____________________________

1,327

(36)

1,156

(15)

1,211

(17)

1,125

1,045

113

138

203

118

—

572

755

224

(29)

—

195

560

132

428

109

127

180

109

(4)

521

635

224

(33)

194

441

111

330

110

121

169

103

(2)

501

710

224

(33)

195

515

196

319

114

234

158

(1)

598

527

211

(35)

184

343

246

113

140

145

(1)

479

566

204

(28)

182

384

142

242

(a) The decrease in operating revenues in 2018 was due to a reduction in taxes collected through our Regulated
Operating Subsidiaries’ Formula Rates as a result of the reduction in the U.S. federal corporate income tax
rate from 35% to 21% effective for tax years beginning after 2017.

(b) We recognized an increase in operating revenues of $69 million in 2019 and a reduction in operating revenues
of $80 million and $115 million in 2016 and 2015, respectively, relating to the refund obligations for the MISO
ROE Complaints as described in Note 19 to the consolidated financial statements.

(c) During 2016, we expensed external legal, advisory and financial services fees of $55 million related to the
Merger Agreement and approximately $41 million due to the accelerated vesting of the share-based awards
that occurred as a result of the Merger Agreement. The external and internal costs related to the Merger
Agreement were recorded at ITC Holdings and have not been included as components of revenue requirement
at our Regulated Operating Subsidiaries.

(d) All amounts presented reflect the change in the authoritative guidance issued by the FASB regarding net
periodic pension and postretirement benefit non-service costs which are now included in the line “Other (income)
and expenses, net”. This change was adopted retrospectively by us in 2018.

(e) The decrease in income tax provision in 2018 was due to the reduction in the U.S. federal corporate income
tax rate from 35% to 21% effective for tax years beginning after 2017. During 2016, we recognized an income
tax benefit of $27 million for excess tax deductions as a result of adopting the accounting guidance associated
with share-based payments.

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(In millions)

BALANCE SHEET DATA:

Cash and cash equivalents

Working capital (deficit)

Property, plant and equipment, net

Goodwill

Total assets

Debt:

ITC Holdings

Regulated Operating Subsidiaries

Total debt

Total stockholder’s equity

(In millions)

CASH FLOWS DATA:

Expenditures for property, plant and

equipment

ITC Holdings and Subsidiaries

December 31,

2019

2018

2017

2016

2015

4 $

6 $

66 $

8 $

(471)
8,582

950
10,058

2,968

2,839

5,807
2,232 $

(308)

7,910

950

9,329

2,767

2,571

5,338

(302)

7,309

950

8,823

2,728

2,373

5,101

(400)

6,698

950

8,223

2,387

2,203

4,590

2,051 $

1,920 $

1,901 $

(550)

6,110

950

7,555

2,304

2,125

4,429

1,709

ITC Holdings and Subsidiaries

Year Ended December 31,

2019

2018

2017

2016

2015

865 $

769 $

755 $

750 $

701

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 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, 2019 and 2018 and provides year-to-year comparisons
between the years ended December 31, 2019 and 2018. Discussions of such information for the year ended
December 31, 2017 and year-to-year comparisons between the years ended December 31, 2018 and 2017 that
are not included in this Form 10-K can be found in “Management’s Discussion and Analysis of Financial Condition

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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, 2018.

Overview

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. 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. Our business strategy is to own, operate, maintain
and invest in transmission infrastructure in order to enhance system integrity and reliability, reduce transmission
constraints and support new generating resources to interconnect to our transmission systems.

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

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.

Significant recent matters that influenced our financial condition, results of operations and cash flows for the

year ended December 31, 2019 or that may affect future results include:

• Our capital expenditures of $865 million at our Regulated Operating Subsidiaries during the year ended
December 31, 2019, as described below under “— Capital Investment and Operating Results Trends,”
resulting primarily from our focus on improving system reliability, increasing system capacity and upgrading
the transmission network to support new generating resources, which includes electric transmission asset
acquisitions from Consumers Energy of $77 million, of which $34 million is an acquisition premium that is
excluded from rate base;

• Debt issuances and repayments as described in Note 11 to the consolidated financial statements, including
the issuance of Senior Secured Notes by METC, First Mortgage Bonds by ITCTransmission and borrowings
under our revolving and term loan credit agreements and commercial paper program to fund capital
investment at our Regulated Operating Subsidiaries as well as for general corporate purposes;

• Issuance of the November 2019 Order related to the MISO ROE Complaints, as described in Note 19 to the
consolidated financial statements, which resulted in a reduction to the base ROE to 9.88% for our MISO
Regulated Operating Subsidiaries, reversal of the amount previously recorded as an estimated current
regulatory liability for refunds relating to the Second Complaint and recording of a current regulatory liability
for our MISO Regulated Operating Subsidiaries of $70 million as of December 31, 2019 for refunds relating
to the Initial Complaint and the period from the date of the September 2016 Order to December 31, 2019;

• The adoption of tax accounting method changes related to bonus depreciation and repairs and maintenance
deductions during the fourth quarter of 2019, which did not have a significant impact on the consolidated
financial statements as of and for the year ended December 31, 2019 but may impact future results; and

• Two notices of inquiry issued by the FERC on March 21, 2019 seeking comments on (1) whether and how
policies concerning the determination of the base ROE for electric utilities should be modified, and (2) its
electric transmission incentives policy.

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

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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 a 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 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 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 allowed returns.

See “Cost-Based Formula Rates with True-Up Mechanism” in Note 6 to the consolidated financial statements
for further discussion of our Formula Rates and see “Rate of Return on Equity Complaints” in Note 19 to the
consolidated financial statements for detail on ROE matters.

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Illustrative Example of Formula Rate Setting

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

financial data.

Line
1

Rate base (a)

Item

Instructions

2 Multiply by 13-month weighted average cost of capital (b)

Allowed return on rate base

(Line 1 x Line 2)

Recoverable operating expenses (including depreciation and

amortization)

Income taxes (c)

6 Gross revenue requirement

____________________________

(Line 3 + Line 4 + Line 5)

Amount

1,000,000

8.38%

83,800

150,000

37,500

271,300

(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 November
2019 Order on the Initial Complaint. See Note 19 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% =
10.63% =

Weighted
Average
Cost of
Capital

2.00%
6.38%
8.38%

is not based on our actual tax expense.

Revenue Accruals and Deferrals — Effects of Monthly Peak Loads

For our MISO Regulated Operating Subsidiaries, monthly 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 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 peak loads do not impact
operating revenues recognized, network load affects the timing of our cash flows from transmission service. The
monthly peak load of our MISO Regulated Operating Subsidiaries is generally impacted by weather and economic
conditions and seasonally shaped with higher load in the summer months when cooling demand is higher.

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. While we
expect increases in rate base to result in a corresponding long-term upward trend in revenues and earnings, our

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revenues and earnings are also impacted by changes in our ROE or required refunds resulting from the resolution
of the incentive adders complaints and MISO ROE Complaints, as described in Note 6 and Note 19 to the
consolidated financial statements, or other future increases or decreases to our rates for incentive adders and
base ROE.

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 the
current transmission infrastructure; (2) enhance system integrity and reliability and accommodate load growth; (3)
upgrade physical and technological grid security; and (4) develop and build regional transmission infrastructure,
including additional transmission facilities that will provide interconnection opportunities for generating facilities.
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)

Expenditures for property, plant and equipment (a)

____________________________

December 31, 2019
$

865 $

2020 — 2024
3,746

(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.

We are pursuing development projects that could result in a significant amount of capital investment, but we
are not able to estimate the amounts we ultimately expect to invest or the timing of such investments. Refer to
“Item 1 Business — Development of Business” for discussion of our development activities.

Investments in property, plant and equipment could be lower than expected due to a variety of factors, as
described 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

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. Prior to the filing of the MISO ROE Complaints,
complaints were filed with the FERC regarding the regional base ROE rate for ISO New England TOs. See Note
19 to the consolidated financial statements for a summary of the MISO ROE Complaints and related proceedings.

Related FERC Orders

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a paper hearing on how the proposed new methodology should apply to the ISO New England TOs ROE complaint
proceedings. The FERC issued a similar order, the November 2018 Order, in the MISO ROE Complaints,
establishing a paper hearing on the application of the proposed new methodology to the proceedings pending
before the FERC involving the MISO TOs’ ROE, including our MISO Regulated Operating Subsidiaries.

The November 2018 Order included preliminary illustrative calculations for the ROE that could have been
established for the Initial Complaint, using the FERC's proposed methodology with financial data from the
proceedings related to that complaint. The FERC’s preliminary calculations were not binding and could change,
as significant changes to the methodology by the FERC were possible as a result of the paper hearing process.
The November 2018 Order and our response to the order through briefs and reply briefs did not provide a reasonable
basis for a change to the reserve or ROEs utilized for any of the complaint refund periods nor all subsequent
periods. On March 21, 2019, the FERC issued a notice of inquiry seeking comments on whether and how policies
concerning the determination of the base ROE for electric utilities should be modified, which is still pending. The
FERC’s consideration of responses to this notice of inquiry may impact our future base ROE.

November 2019 Order

On November 21, 2019, the FERC issued an order on the MISO ROE Complaints. The FERC did not adopt
the methodology proposed in the November 2018 Order, which had proposed using four financial models to
establish the base ROE. Instead, the FERC determined that two financial models should be used to determine
the base ROE. The FERC applied that methodology to the Initial Complaint period and 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%. 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. 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, and the base ROE
for that period should be 12.38% plus applicable incentive adders. As a result, we have reversed the aggregate
estimated current liability we had previously recorded for the Second Complaint, as noted below in “Financial
Statement Impacts”. In addition, from May 12, 2016 to September 27, 2016, the base ROE should be 12.38% plus
applicable incentive adders, because no complaint had been filed for that period and no refund is due during that
period. The FERC ordered refunds to be made in accordance with the November 2019 Order within 30 days, but
on December 18, 2019 the FERC granted a request from MISO for an extension until December 23, 2020 for
settlement of the refunds. 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 filed their request for rehearing
primarily on the basis that the methodology applied by the FERC in the November 2019 Order will 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 rehearings for further consideration.

In January 2020, certain complainants in the MISO ROE dockets filed an appeal of the September 2016
Order and the November 2019 Order at the D.C. Circuit Court. We believe that the appeal was premature and
should be dismissed, but if not, we will respond in due course.

Financial Statement Impacts

As of December 31, 2019, we had recorded a current regulatory liability in the consolidated statements of
financial position of $70 million to reflect amounts due to customers under the terms outlined in the November
2019 Order on the Initial Complaint and the period from the date of the September 2016 Order to December 31,
2019. We had recorded an aggregate estimated current regulatory liability in the consolidated statements of financial
position of $151 million as of December 31, 2018 for the Second Complaint, which was reversed in November
2019 following the November 2019 Order. Although the November 2019 Order dismissed the Second Complaint
with no refunds required, it is possible upon rehearing that our MISO Regulated Operating Subsidiaries will be
required to provide refunds related to the Second Complaint and these refunds could be material. It is also possible,
upon rehearing of the November 2019 Order, that the outcome may differ materially from the November 2019
Order. In 2017, $118 million, including interest, was refunded to customers of our MISO Regulated Operating
Subsidiaries for the Initial Complaint based on the refund liability associated with the September 2016 Order.

Our MISO Regulated Operating Subsidiaries currently record revenues at the base ROE of 9.88% established
in the November 2019 Order plus applicable incentive adders. See Note 6 to the consolidated financial statements
for a summary of incentive adders for transmission rates.

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The recognition of the obligations associated with the MISO ROE Complaints resulted in the following impacts

to the consolidated statements of comprehensive income during each respective period:

(In millions)

Revenue increase (decrease)

Interest expense increase (decrease)

Estimated net income increase (decrease)

Year Ended December 31,

2019

2018

2017

69 $

1 $

(12)

(4)

—

(3)

As of December 31, 2019, 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.

Challenges to Incentive Adders for Transmission Rates

On March 21, 2019, the FERC issued a notice of inquiry seeking comments on its electric transmission incentives
policy, which is still pending. The FERC’s consideration of responses to this inquiry may impact the incentive adders
that our Regulated Operating Subsidiaries are authorized to apply to their base ROEs. See Note 6 to the
consolidated financial statements for a summary of incentive adders for transmission rates.

MISO Regulated Operating Subsidiaries

On April 20, 2018, Consumers Energy, IP&L, Midwest Municipal Transmission Group, Missouri River Energy
Services, Southern Minnesota Municipal Power Agency and WPPI Energy filed a complaint with the FERC under
section 206 of the FPA, challenging the adders for independent transmission ownership that are included in
transmission rates charged by the MISO Regulated Operating Subsidiaries. The adders for independent
transmission ownership allowed up to 50 basis points or 100 basis points to be added to the MISO Regulated
Operating Subsidiaries’ authorized ROE, subject to any ROE cap established by the FERC. On October 18, 2018,
the FERC issued an order granting the complaint in part, setting revised adders for independent transmission
ownership for each of the MISO Regulated Operating Subsidiaries to 25 basis points, and requiring the MISO
Regulated Operating Subsidiaries to include the revised adders, effective April 20, 2018, in their Formula Rates.
In addition, the order directed the MISO Regulated Operating Subsidiaries to provide refunds, with interest, for
the period from April 20, 2018 through October 18, 2018. The MISO Regulated Operating Subsidiaries began
reflecting the 25 basis point adder for independent transmission ownership in transmission rates in November
2018. Refunds of $7 million were primarily made in the fourth quarter of 2018 and were completed in the first
quarter of 2019. The MISO Regulated Operating Subsidiaries sought rehearing of the FERC’s October 18, 2018
order, and on July 18, 2019, the FERC denied the rehearing request. On September 11, 2019, the MISO Regulated
Operating Subsidiaries filed an appeal of the FERC’s order in the D.C. Circuit Court. On December 16, 2019, the
D.C. Circuit Court established a briefing schedule for the appeal. Initial briefs were filed on January 27, 2020 and
reply briefs are due to be filed in the second quarter of 2020. We do not expect the final resolution of this proceeding
to have a material adverse impact on our consolidated results of operations, cash flows or financial condition.

ITC Great Plains

On June 11, 2019, KCC filed a complaint with the FERC under section 206 of the FPA, challenging the ROE
adder for independent transmission ownership that is included in the transmission rate charged by ITC Great
Plains. The complaint argues that because ITC Great Plains is similarly situated to our MISO Regulated Operating
Subsidiaries with respect to ownership by Fortis and GIC, the same rationale by which the FERC lowered the
MISO Regulated Operating Subsidiaries adders for independent transmission ownership, as discussed above,
also applies to ITC Great Plains. The adder for independent transmission ownership allows up to 100 basis points
to be added to the ITC Great Plains authorized ROE, subject to any ROE cap established by the FERC. ITC Great
Plains filed an answer to the complaint on July 1, 2019 asking the FERC to deny the complaint since KCC showed
no evidence that ITC Great Plains’ independence or the benefits it provides as an independent TO has been
compromised or reduced as a result of the Fortis and GIC acquisition. As of December 31, 2019, we had recorded
an estimated current regulatory liability of $2 million related to this complaint. We do not expect the resolution of
this proceeding to have a material adverse impact on our consolidated results of operations, cash flows or financial
condition.

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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 agent 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 MVP projects such as our portion of four MVPs in the
ITC Midwest footprint and the Thumb Loop Project in the Michigan footprint. 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 is 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 maintenance, 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 and business development organizations, 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 allowed 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)
OPERATING REVENUES

Year Ended
December 31,

2019

2018

Increase
(Decrease)

Percentage
Increase
(Decrease)

Year Ended
December 31,
2017

Increase
(Decrease)

Percentage
Increase
(Decrease)

Transmission and other services

1,286

1,192

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 (income) and expenses, net

Total other expenses (income)

INCOME BEFORE INCOME TAXES

INCOME TAX PROVISION

NET INCOME

1,327

(36)

1,156

113

138

203

118

—

572

755

224

(29)

—

195

560

132

428

109

127

180

109

(4)

521

635

224

(33)

194

441

111

330

171

120

—

(3)

119

8 % $

1,226

(214)%

15 %

4 %

9 %

13 %

8 %

(100)%

10 %

19 %

— %

(12)%

(100)%

1 %

27 %

19 %

30 % $

(15)

1,211

110

121

169

103

(2)

501

710

224

(33)

195

515

196

319

(34)

(21)

(55)

(1)

(2)

(75)

—

(1)

(74)

(85)

(3)%

140 %

(5)%

(1)%

5 %

7 %

6 %

100 %

4 %

(11)%

— %

(25)%

(1)%

(14)%

(43)%

3 %

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Operating Revenues

Year ended December 31, 2019 compared to year ended December 31, 2018

The following table sets forth the components of and changes in operating revenues for the year ended December
31, 2019 and 2018 which included revenue accruals and deferrals in Note 6 to the consolidated financial statements:

(In millions)
Network revenues (a)

Regional cost sharing revenues (a)

Point-to-point

Scheduling, control and dispatch (a)

Other

Recognition of liabilities for MISO ROE

Complaints

Total

2019

2018

Amount

Percentage

Amount

Percentage

Increase
(Decrease)
65

67% $

836

371
13

63% $

28%

771

334

29%

—%

1,327

100% $

1,156

100% $

Percentage
Increase
(Decrease)

8 %

11 %

(7)%

13 %

— %

(1)

—

171

6,800 %

15 %

____________________________
(a) Includes a portion of the Formula Rate true-up of $41 million and $(36) million for the year ended December

31, 2019 and 2018, respectively.

Network revenues increased primarily due to higher net network revenue requirements at our Regulated
Operating Subsidiaries, partially offset by an increase in revenue credits resulting from higher regional cost sharing
revenue requirements, during the year ended December 31, 2019 compared to the same period in 2018. Higher
net network revenue requirements were due primarily to a higher rate base associated with higher balances of
property, plant and equipment in service.

Regional cost sharing revenues increased primarily due to additional capital projects eligible for regional cost
sharing and these projects being placed into service, in addition to higher accumulated investment for existing
regional cost sharing projects for the year ended December 31, 2019 compared to the same period in 2018.

During the year ended December 31, 2019, adjustments were made to the refund liability recorded related to
the MISO ROE Complaints, as described in Note 19 to the consolidated financial statements, which resulted in a
net increase in operating revenues of $69 million for the year ended December 31, 2019 compared to the same
period in 2018. As a result of the November 2019 Order, operating revenues increased $133 million due to the
dismissal of the Second Complaint, which was partially offset by a revenue decrease of $64 million for the
establishment of an additional refund liability for the Initial Complaint and the period from the date of the September
2016 Order to December 31, 2019.

Operating Expenses

General and administrative expenses

Year ended December 31, 2019 compared to year ended December 31, 2018

General and administrative expenses increased primarily due to higher compensation-related expenses
resulting from additional share-based compensation expense of $23 million. This increase was partially offset by
lower professional services, such as legal and advisory service fees, related to various development initiatives of
$15 million.

Depreciation and amortization expenses

Year ended December 31, 2019 compared to year ended December 31, 2018

Depreciation and amortization expenses increased primarily due to a higher depreciable base resulting from

property, plant and equipment in-service additions.

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Taxes other than income taxes

Year ended December 31, 2019 compared to year ended December 31, 2018

Taxes other than income taxes increased due to higher property tax expenses primarily due to our Regulated
Operating Subsidiaries’ 2018 capital additions, which were included in the assessments for 2019 property taxes.

Other Expenses (Income)

Interest Expense, Net

Year ended December 31, 2019 compared to year ended December 31, 2018

Interest expense, net remained consistent due to higher debt balances offset by the reversal of interest expense
previously recorded for the Second Complaint pursuant to the November 2019 Order, as described in Note 19 to
the consolidated financial statements.

Income Tax Provision

Year ended December 31, 2019 compared to year ended December 31, 2018

Our effective tax rates for the years ended December 31, 2019 and 2018 were 23.6% and 25.2%, respectively.
Our effective tax rate as of December 31, 2019 exceeded our 21% statutory federal income tax rate primarily due
to state income taxes, partially offset by AFUDC equity. During the year ended December 31, 2018, Iowa enacted
a reduction in corporate statutory income tax rates from 12.0% to 9.8%, effective January 1, 2021. Based upon
the future change in Iowa’s tax rate, we revalued the Iowa NOLs at ITC Holdings in 2018. As a result, additional
income tax expense was recorded for the year ended December 31, 2018 compared to the same period in 2019.
The amount of income tax expense relating to AFUDC equity was recognized as a regulatory asset and is not
included in the income tax provision. See Note 12 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 and term loan credit agreements (the terms
of which are described in Note 11 to the consolidated financial statements). In addition, we may from time to time
secure debt funding in the capital markets, although we can provide no assurance that we will be able to obtain
financing on favorable terms or at all. As market conditions warrant, we may also from time to time repurchase
debt securities issued by us, in the open market, in privately negotiated transactions, by tender offer or otherwise.
We expect that our capital requirements will arise principally from our need to:

• Fund capital expenditures 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 business development expenses and related capital expenditures. We are pursuing development
activities for projects that could result in significant development expenses and capital expenditures
incremental to our current plan. Refer to Note 19 to the consolidated financial statements for a discussion
of contingent payments related to development projects.

• Fund working capital requirements.

• Fund our debt service requirements, including principal repayments and periodic interest payments, which

are further described in detail below under “— Contractual Obligations.”

• Fund any refund obligation in connection with the pending ROE matters.

In addition to the expected capital requirements above, any adverse determinations or settlements relating to
the regulatory matters or contingencies described in Notes 6 and 19 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 needs. We
rely on both internal and external sources of liquidity to provide working capital and fund capital investments. ITC
Holdings’ sources of cash are dividends and other payments received by us from our Regulated Operating

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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 and term loan credit agreements
as well as our cash and cash equivalents as needed to meet our short-term cash requirements. As of December 31,
2019, we had consolidated indebtedness under our revolving and term loan credit agreements of $499 million,
with unused capacity under our revolving credit agreements of $601 million and unused capacity under our term
loan credit agreement of $200 million. In January 2020, ITC Holdings drew upon the remaining $200 million under
the term loan credit agreement, which was used to repay outstanding commercial paper balances. ITC Holdings
had $200 million of commercial paper issued and outstanding, net of discount, as of December 31, 2019, with the
ability to issue an additional $200 million under the commercial paper program. See Note 11 to the consolidated
financial statements for a detailed discussion of the commercial paper program, our revolving and term loan credit
agreements and other debt activity during the years ended December 31, 2019 and 2018.

To address our long-term capital requirements, we expect that we will need to obtain additional debt financing.
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 reasonably satisfactory
to us due to our strong credit ratings and our historical ability to obtain financing.

We have material exposure to LIBOR through the revolving credit agreements of ITC Holdings and certain of
our Regulated Operating Subsidiaries. It is expected that LIBOR will be discontinued and, while we believe an
acceptable replacement rate will be available if LIBOR is discontinued, we cannot reasonably estimate the expected
impact, if any, of such a discontinuation.

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

Rating

BBB+
A-2

S&P (a)

Moody’s

Outlook

Rating

Outlook

Negative
Negative

Negative

Baa2
Prime-2

Stable
Stable

Stable

____________________________

(a) On September 26, 2019, S&P revised the ratings of senior unsecured notes at ITC Holdings from A- to BBB
+, reflecting expected increases in the ratio of debt at our Regulated Operating Subsidiaries relative to amounts
at ITC Holdings. All other ratings were reaffirmed and the outlook remains unchanged.

Covenants

Our debt instruments contain numerous financial and operating covenants that place significant restrictions on
certain transactions, such as incurring additional indebtedness, engaging in sale and lease-back transactions,
creating liens or other encumbrances, entering into mergers, consolidations, liquidations or dissolutions, creating
or acquiring subsidiaries and selling or otherwise disposing of all or substantially all of our assets. In addition, the

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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, 2019, 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)
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

Contributions in aid of construction

Other

Net cash used in investing activities

CASH FLOWS FROM FINANCING ACTIVITIES

Net issuance/repayment 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

Year Ended December 31,
2018

2017

2019

428 $

330 $

319

203

(55)
135
(82)
629

(865)
10
1
(854)

463
(250)

11
(3)
221

(4)
10

180

17
107
19
653

(769)
21
1
(747)

238
(200)

3
(5)
36

(58)
68
10 $

169

34
195
(110)
607

(755)
21
(10)
(744)

511
(300)

(12)
(5)
194

57
11
68

CASH, CASH EQUIVALENTS AND RESTRICTED CASH — End of period

6 $

Cash Flows From Operating Activities

Year ended December 31, 2019 compared to year ended December 31, 2018

Net cash provided by operating activities was $629 million and $653 million for the year ended December 31,
2019 and 2018, respectively. The decrease in cash provided by operating activities was due primarily to lower tax
refunds received of $12 million, higher interest payments of $5 million and higher property tax payments of $7
million during the year ended December 31, 2019 compared to the same period in 2018.

Cash Flows From Investing Activities

Year ended December 31, 2019 compared to year ended December 31, 2018

Net cash used in investing activities was $854 million and $747 million for the year ended December 31, 2019
and 2018, respectively. The increase in cash used in investing activities was primarily due to an increase in capital
expenditures of $96 million, including the electric transmission asset acquisition of $76 million from Consumer’s
Energy, and a decrease in contributions received in aid of construction of $11 million during the year ended
December 31, 2019 compared to the same period in 2018.

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Cash Flows From Financing Activities

Year ended December 31, 2019 compared to year ended December 31, 2018

Net cash provided by financing activities was $221 million and $36 million for the year ended December 31,
2019 and 2018, respectively. The increase in cash provided by financing activities was due primarily to an increase
in net borrowings under our revolving and term loan credit agreements of $353 million and an increase in net
issuances of commercial paper of $200 million during the year ended December 31, 2019 compared to the same
period in 2018. These increases were partially offset by a decrease in issuances of long-term debt of $225 million,
an increase in retirement of long-term debt of $103 million and an increase in dividend payments of $50 million
during the year ended December 31, 2019 compared to the same period in 2018. See Note 11 to the consolidated
financial statements for detail on the issuances and retirements of debt, borrowings under our term loan credit
agreement and a description of our revolving credit agreements and commercial paper program.

Contractual Obligations

The following table details our contractual obligations as of December 31, 2019:

(In millions)
Debt:

ITC Holdings Senior Notes

ITC Holdings revolving credit agreement (a)

ITC Holdings commercial paper program

ITC Holdings term loan credit agreement

ITCTransmission First Mortgage Bonds

ITCTransmission revolving credit agreement (a)

METC Senior Secured Notes

METC revolving credit agreement (a)

ITC Midwest First Mortgage Bonds

ITC Midwest revolving credit agreement (a)

ITC Great Plains First Mortgage Bonds

ITC Great Plains revolving credit agreement (a)

Interest payments:

ITC Holdings Senior Notes

ITCTransmission First Mortgage Bonds

METC Senior Secured Notes

ITC Midwest First Mortgage Bonds

ITC Great Plains First Mortgage Bonds

Operating leases

Purchase obligations

Regulatory liabilities — revenue deferrals,

including accrued interest

Regulatory liabilities — refund related to the
MISO ROE Complaints, including accrued
interest (b)

METC Easement Agreement

Total obligations

____________________________

Total

Due within
1 Year

Due in
Years 2-3

Due in
Years 4-5

Due after
5 years

2,550 $
34

200

785
24

575
79

1,085

130

150
32

944

888

622
1,106

155
4

309
10,071 $

— $

500 $

650 $

1,400

—

200

—

200

—

130

—

192

—

143

—

785

—

575

—

975

—

150

—

512

713

500

872

125

—

259

652 $

1,439 $

1,113 $

6,867

(a) On January 10, 2020 we extended the maturity date of our revolving credit agreements from October 21, 2022
to October 20, 2023. Refer to Note 11 to the consolidated financial statements for further details on the extension.

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(b) Amount reflects terms outlined in the November 2019 Order related to the MISO ROE Complaints, as described

in Note 19 to the consolidated financial statements.

Interest payments included above relate only to our fixed-rate long-term debt outstanding at December 31,
2019. We also expect to pay interest and commitment fees under our variable-rate revolving and term loan credit
agreements and commercial paper program that have not been included above due to varying amounts of
borrowings and interest rates under the facilities. In 2019, we paid $16 million of interest and commitment fees
under our revolving and term loan credit agreements and commercial paper program.

Operating leases include leases for office space, equipment and storage facilities. Purchase obligations
represent commitments primarily for materials, services and equipment that had not been received as of
December 31, 2019, primarily for construction and maintenance projects for which we have an executed contract.
The majority of the items relate to materials and equipment that have long production lead times. See Note 10 and
Note 19 to the consolidated financial statements for more information on our operating leases and purchase
obligations, respectively.

The revenue deferrals, including accrued interest, in the table above represent the over-recovery of revenues
resulting from differences between the amounts billed to customers and actual revenue requirement at each of
our Regulated Operating Subsidiaries, as described in Note 6 to the consolidated financial statements. These
amounts will offset future revenue requirement for purposes of calculating our Formula Rates as part of the true-
up mechanism in our rate construct.

The Easement Agreement provides METC with an easement 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. 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 of at least one year in advance. Payments to Consumers Energy under the Easement Agreement are
charged to operation and maintenance expense.

The contractual obligations table above excludes certain items, including contingent liabilities and other current
and long-term liabilities, due to uncertainty regarding the timing and any amount of future cash flows necessary
to settle these obligations. Items excluded from the contractual obligations table include:

•

long-term incentive awards;

pension and other postretirement obligations;

regulatory liabilities related to asset removal costs and income taxes refundable related to implementation
of the TCJA; and

•

liabilities to refund deposits from generators for transmission network upgrades.

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 is a list of accounting policies that are most significant to the portrayal of our financial condition

and results of operations and/or that require management’s most difficult, subjective or complex judgments.

Regulation

Our Regulated Operating Subsidiaries are subject to rate regulation by the FERC. As a result, we apply
accounting principles in accordance with the standards set forth by the FASB for accounting for the effects of
certain types of regulation. Use of this accounting guidance results in differences in the application of GAAP
between regulated and non-regulated businesses and requires the recording of regulatory assets and liabilities
for certain transactions that would have been treated as expense or revenue in non-regulated businesses. As
described in Note 7 to the consolidated financial statements, we had regulatory assets and liabilities of $241 million

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and $707 million, respectively, as of December 31, 2019. 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 $33 million relating to intangible assets
at December 31, 2019 that are described in Note 9 to the consolidated financial statements.

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 a 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. The cost-based 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 subsequently collect or refund any over-recovery or under-
recovery of revenues, as appropriate. 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 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 7 to the consolidated financial statements for the regulatory assets and liabilities recorded at our
Regulated Operating Subsidiaries’ as a result of the Formula Rate revenue accruals and deferrals.

Valuation of Goodwill

We have goodwill resulting from our acquisitions of ITCTransmission and METC and ITC Midwest’s acquisition
of the IP&L transmission assets. We perform an impairment test annually at the reporting unit level or whenever
events 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. In order to perform an impairment assessment, 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 performing
a qualitative assessment, we assess macroeconomic conditions, industry and market considerations, cost factors,
overall financial performance, entity-specific considerations, and industry-specific considerations such as our
regulatory environment and rate structure. If, after assessing the totality of events or circumstances, we determine
it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, then performing
a quantitative impairment analysis is unnecessary.

If we determine a quantitative analysis is necessary or we elect to bypass the qualitative assessment, we
compare the fair value of each reporting unit with their respective carrying value. We determine fair value using
valuation techniques based on discounted future cash flows under various scenarios. We also consider estimates
of market-based valuation multiples for companies within the peer group of our reporting units. The market-based
multiples involve judgment regarding the appropriate peer group and the appropriate multiple to apply in the
valuation and the cash flow estimates involve judgments based on a broad range of assumptions, information and
historical results. To the extent estimated market-based valuation multiples and/or discounted cash flows are

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revised downward, we may be required to write down all or a portion of goodwill, which would adversely impact
earnings.

As of December 31, 2019 and 2018, consolidated goodwill totaled $950 million. We completed our annual
goodwill impairment test for our reporting units as of October 1, 2019 using a qualitative assessment and determined
that no impairment exists. There were no events subsequent to October 1, 2019 that indicated impairment of our
goodwill. We do not believe there is a material risk of our goodwill being impaired in the near term for any of our
reporting units.

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. Additionally, we have
other contingent obligations that may be required to be paid to developers based on achieving certain milestones
relating to development initiatives. We periodically evaluate our exposure to such contingencies and record liabilities
for those matters where a loss is considered probable and reasonably estimable. 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. 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.

• Completion of certain milestones relating to development initiatives.

Refer to Note 19 to the consolidated financial statements for discussion on contingencies, including the MISO

ROE Complaints.

Pension and Postretirement Costs

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, including rates of
return on plan assets, the discount rates, the rate of increase in health care costs, the amount and timing of plan
sponsor contributions and demographic factors such as retirements, mortality and turnover, among others. We
evaluate these assumptions annually and update them periodically to reflect our actual experience. Three critical
assumptions in determining our periodic costs and obligations are discount rate, expected long-term return on plan
assets and the rate of increases in health care costs. The discount rate represents the market rate for synthesized
AA-rated zero-coupon bonds with durations corresponding to the expected durations of the benefit obligations and
is used to calculate the present value of the expected future cash flows for benefit obligations under our plans. 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. Assumed health care
cost trend rates may have a significant effect on the amounts reported for the health care plans.

Off-Balance Sheet Arrangements

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

financial condition.

Recent Accounting Pronouncements

See Note 2 to the consolidated financial statements.

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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 and term loan
credit agreements and commercial paper, was $5,672 million at December 31, 2019. 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 and term loan credit agreements and commercial paper, was $5,108 million at December 31,
2019. We performed an analysis calculating the impact of changes in interest rates on the fair value of long-term
debt and debt maturing within one year, excluding revolving and term loan credit agreements and commercial
paper at December 31, 2019. An increase in interest rates of 10% (from 5.0% to 5.5%, for example) at December 31,
2019 would decrease the fair value of debt by $210 million, and a decrease in interest rates of 10% at December 31,
2019 would increase the fair value of debt by $226 million at that date.

Revolving and Term Loan Credit Agreements

At December 31, 2019, we had a consolidated total of $499 million outstanding under our revolving and term
loan credit agreements, which are variable rate loans and fair value approximates book value. A 10% increase or
decrease in borrowing rates under the revolving and term loan credit agreements compared to the weighted average
rates in effect at December 31, 2019 would increase or decrease interest expense by $1 million for an annual
period with a constant borrowing level of $499 million.

Commercial Paper

At December 31, 2019, ITC Holdings had $200 million 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 would
increase or decrease interest expense by less than $1 million for an annual period with a continuous level of
commercial paper outstanding of $200 million.

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.

As of December 31, 2019, we held 5-year interest rate swap contracts with a notional amount of $200 million,
which manage interest rate risk associated with the refinancing of the $400 million term loan at ITC Holdings with
a maturity date of June 11, 2021. As of December 31, 2019, ITC Holdings had $200 million outstanding under the
term loan credit agreement. In January 2020, ITC Holdings drew upon the remaining $200 million under the term
loan credit agreement. In January 2020, ITC Holdings entered into three 5-year interest rate swap contracts with
notional amounts of $63 million. See Note 11 to the consolidated financial statements for further discussion on
these interest rate swaps.

Credit Risk

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2019 operating revenues but will not be billed to our customers until 2021. 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

Consolidated Statements of Financial Position as of December 31, 2019 and 2018

Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2019, 2018 and 2017

Consolidated Statements of Changes in Stockholder’s Equity for the Years Ended December 31, 2019, 2018 and
2017

Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 2018 and 2017

Notes to Consolidated Financial Statements

Schedule I — Condensed Financial Information of Registrant

Page

129

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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 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, 2019.

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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, 2019 and 2018, the related consolidated statements of
comprehensive income, changes in stockholder’s equity, and cash flows for each of the three years in the period
ended December 31, 2019, 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
aspects, the financial condition of the Company as of December 31, 2019 and 2018, and the results of its operations
and its cash flows for each of the three years in the period ended December 31, 2019, 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.

/s/ DELOITTE & TOUCHE LLP

Detroit, Michigan
February 12, 2020

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, except share data)

ASSETS

Current assets

Cash and cash equivalents

Accounts receivable

Inventory

Regulatory assets

Income tax receivable

Prepaid and other current assets

Total current assets

December 31,

2019

2018

117

—

187

102

164

Property, plant and equipment (net of accumulated depreciation and amortization of $1,930 and

$1,779, respectively)

8,582

7,910

Other assets

Goodwill

Intangible assets (net of accumulated amortization of $42 and $39, respectively)

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

950

229

1,289

10,058

123

235

658

873

584

950

200

1,255

9,329

106

178

—

472

721

640

5,572

5,338

Commitments and contingent liabilities (Notes 6 and 19)

STOCKHOLDER’S EQUITY

Common stock, without par value, 235,000,000 shares authorized, 224,203,112 shares issued and

outstanding at December 31, 2019 and 2018

Retained earnings

Accumulated other comprehensive income

Total stockholder’s equity

892

1,333

2,232

TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY

10,058

See notes to consolidated financial statements.

892

1,155

2,051

9,329

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ITC HOLDINGS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In millions)

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 (income) and expenses, net

Total other expenses (income)

INCOME BEFORE INCOME TAXES

INCOME TAX PROVISION

NET INCOME

OTHER COMPREHENSIVE INCOME (LOSS)

Derivative instruments, net of tax (Note 15)

TOTAL OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX

Year Ended December 31,

2019

2018

2017

1,286

1,192

1,327

(36)

1,156

1,226

(15)

1,211

113

138

203

118

—

572

755

224

(29)

—

195

560

132

428

109

127

180

109

(4)

521

635

224

(33)

194

441

111

330

110

121

169

103

(2)

501

710

224

(33)

195

515

196

319

—

319

TOTAL COMPREHENSIVE INCOME

431

331

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)

BALANCE, DECEMBER 31, 2016

Net income

Dividends to ITC Investment Holdings

BALANCE, DECEMBER 31, 2017

Opening balance reclassification

Net income

Dividends to ITC Investment Holdings

Other comprehensive income, net of tax (Note 15)

BALANCE, DECEMBER 31, 2018

Net income

Dividends to ITC Investment Holdings

Other comprehensive income, net of tax (Note 15)

BALANCE, DECEMBER 31, 2019

Accumulated
Other

Total

Common Stock

Retained
Earnings

Comprehensive Stockholder’s
Income (Loss)

Equity

892

1,007

—

319

(300)

892

1,026

—

(1)

330

(200)

—

892

1,155

—

428

(250)

—

892

1,333

—

1,901

319

(300)

1,920

—

330

(200)

2,051

428

(250)

2,232

See notes to consolidated financial statements.

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ITC HOLDINGS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

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

Income tax receivable

Accounts payable

Accrued interest

Accrued taxes

Net refund 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

Contributions in aid of construction

Other

Net cash used in investing activities

CASH FLOWS FROM FINANCING ACTIVITIES

Issuance of long-term debt, net of discount

Borrowings under revolving credit agreements

Borrowings under term loan credit agreements

Net (repayment) issuance of commercial paper, net of discount

Retirement of long-term debt — including extinguishment of debt costs

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,

2019

2018

2017

428

330

319

203

(55)

135

(29)

(10)

(11)

(2)

(82)

629

180

107

(33)

(10)

653

(865)

(769)

(854)

(747)

169

195

(33)

(17)

—

(3)

(113)

607

(755)

(10)

(744)

175

1,090

200

(203)

(999)

—

(250)

19
(8)

(3)
221

(4)

400

832

—

(100)

(844)

(50)

(200)

6
(3)

(5)
36

(58)

1,199

1,065

250

(148)

(477)

(1,178)

(200)

(300)

16
(28)

(5)
194

CASH, CASH EQUIVALENTS AND RESTRICTED CASH — End of period

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. In 2016,
ITC Holdings became a wholly-owned subsidiary of ITC Investment Holdings. Fortis owns a majority indirect equity
interest in ITC Investment Holdings, with GIC holding an indirect equity interest of 19.9%. 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. Our business strategy is
to own, operate, maintain and invest in transmission infrastructure in order to enhance system integrity and reliability,
reduce transmission constraints and support new generating resources to interconnect to our transmission systems.

Our Regulated Operating Subsidiaries are independent electric transmission utilities, with rates regulated by
the FERC and established on a cost-of-service model. 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 and 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. ITC Interconnection currently owns assets in Michigan and
earns revenues based on its facilities reimbursement agreement with a merchant generating company.

2. RECENT ACCOUNTING PRONOUNCEMENTS

Recently Adopted Pronouncements

Accounting for Leases

Effective January 1, 2019, we adopted accounting guidance that requires lessees to recognize a right-of-use
asset and lease liability for most leases, along with additional quantitative and qualitative disclosures. We elected
to apply transition relief which permitted us to adopt the new guidance on a modified retrospective basis at the
adoption date (i.e., January 1, 2019) as opposed to at the beginning of the earliest period presented in the financial
statements (i.e., January 1, 2017). Therefore, while we began applying the new guidance as of January 1, 2019,
prior period comparative financial statements and disclosures will continue to be presented under previous lease
accounting guidance.

In connection with our adoption of the new guidance, we elected various practical expedients and made certain

accounting policy elections, including:

•

a “package of three” practical expedients that must be taken together and allowed us to not reassess:

whether any expired or existing contract is a lease or contains a lease,

the lease classification of any expired or existing leases, and

the initial direct costs for any existing leases;

•

a practical expedient that permits entities to not evaluate existing land easements at adoption that were
not previously accounted for as leases; and

an accounting policy election to not apply the recognition requirements to short-term leases (i.e., leases
with terms of 12 months or less).

Our leasing activities primarily relate to office facilities, but we also have limited leasing activity relating to
equipment and storage facilities. As of January 1, 2019, adoption of the guidance resulted in recognition of right-
of-use lease assets of $3 million, current lease liabilities of $1 million, and non-current lease liabilities of $2 million.
The adoption of this guidance did not have any impact on retained earnings or net income. We also added
disclosures as a result of our adoption of the guidance; refer to Note 10 for more information on our leasing activities.

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Targeted Improvements to Accounting for Hedging Activities

In August 2017, the FASB issued authoritative guidance to make targeted improvements to hedge accounting
to better align with an entity’s risk management objectives and to reduce the complexity of hedge accounting.
Among other changes, the new guidance simplifies hedge accounting by (a) allowing more time for entities to
complete initial quantitative hedge effectiveness assessments, (b) enabling entities to elect to perform subsequent
effectiveness assessments qualitatively, (c) eliminating the concept of recognizing periodic hedge ineffectiveness
for cash flow hedges, (d) requiring the change in fair value of a derivative to be recorded in the same consolidated
statements of comprehensive income line item as the earnings effect of the hedged item, and (e) permitting
additional hedge strategies to qualify for hedge accounting. In addition, the guidance modifies existing disclosure
requirements and adds new disclosure requirements. We adopted the guidance as of January 1, 2019; however,
adoption of the accounting standard did not have a material impact on our financial statements or disclosures.

Pension and Other Postretirement Plan Disclosures

In August 2018, the FASB issued authoritative guidance modifying the disclosure requirements for defined
benefit pension and other postretirement plans. The new guidance requires disclosures including (a) the weighted
average interest credit rates used for cash balance pension plans, (b) a narrative description of the reasons for
significant gains and losses affecting the benefit obligation for the period, and (c) an explanation of other significant
changes in the benefit obligation or plan assets. In addition, the guidance removes previously required disclosures
including, among others, the requirement for public entities to disclose the effects of a one-percentage-point change
on the assumed health care costs and the effect of the change in rates on service cost, interest cost, and the
benefit obligation for postretirement health care benefits. The new guidance, which is effective for fiscal years
ending after December 15, 2020 with early adoption permitted, is required to be adopted on a retrospective basis.
We early adopted this guidance in the 2019 consolidated financial statements and adjusted our disclosures
accordingly.

Recently Issued Pronouncements

We have considered all new accounting pronouncements issued by the FASB and concluded the following
accounting guidance, which has not yet been adopted by us, may have a material impact on our consolidated
financial statements.

Accounting for Cloud Computing Arrangements

In August 2018, the FASB issued authoritative guidance to address the accounting for implementation costs
incurred in a cloud computing agreement that is a service contract. The new standard aligns the accounting for
implementation costs incurred in a cloud computing arrangement as a service contract with existing guidance on
capitalizing costs associated with developing or obtaining internal-use software. In addition, the new guidance
requires entities to expense capitalized implementation costs of a cloud computing arrangement that is a service
contract over the term of the agreement and to present the expense in the same income statement line item as
the hosting fees. The guidance is effective for fiscal years beginning after December 15, 2019 with early adoption
permitted; however, we have elected not to early adopt. Prospective or retrospective adoption is permitted; we
plan to adopt prospectively. We do not expect adoption of this standard to have a material impact on our annual
consolidated financial statements.

3. SIGNIFICANT ACCOUNTING POLICIES

A summary of the major accounting policies followed in the preparation of the accompanying consolidated

financial statements, which conform to GAAP, is presented below:

Principles of Consolidation — ITC Holdings consolidates its majority owned subsidiaries. We eliminate

all intercompany balances and transactions.

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

Regulation — Our Regulated Operating Subsidiaries are subject to the regulatory jurisdiction of the FERC,
which issues orders pertaining to rates, recovery of certain costs, including the costs of transmission assets
and regulatory assets, conditions of service, accounting, financing authorization and operating-related

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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 as revenue and expense 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.

Accounts Receivable — We recognize losses for uncollectible accounts based on specific identification
of any such items. As of December 31, 2019, 2018 and 2017 we did not have an accounts receivable reserve.

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 $194 million, $170 million and $160 million for 2019, 2018 and 2017, respectively.

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.
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 2.0% for 2019, 2018 and 2017. 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 45 to 60 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 the 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 $8 million for 2019 and $9 million for 2018 and 2017.

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 inventory stated at original cost consisting of

items that are expected to be used exclusively for capital projects.

Property, plant and equipment at ITC Holdings and 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 generator interconnection
agreements. The generator interconnection agreements typically consist of both transmission network
upgrades, which are a category of upgrades deemed by the FERC to benefit the transmission system as a

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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. As a result, generator interconnection
agreements 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.

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.

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 fixed income security
investments primarily fund our two supplemental nonqualified, noncontributory, retirement benefit plans for
selected management employees as described in Note 13. Beginning on January 1, 2018, all gains and
losses associated with our mutual funds as described in Note 14 are recorded in earnings. Previously,
unrealized gains and losses on certain available-for-sale investments were recorded in AOCI.

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 and Other Intangible Assets — 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.

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, 2019 and
determined that no impairment exists. There were no events subsequent to October 1, 2019 that indicated
impairment of our goodwill. Our intangible assets other than goodwill have finite lives and are amortized
over their useful lives. Refer to Note 9 for additional discussion on our goodwill and intangible assets.

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 issue. 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 issue. We recorded $5 million during the years ended December 31, 2019
and 2018 and $4 million during the year ended December 31, 2017 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

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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 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. There were no significant changes to our asset retirement obligations in 2019. Our
asset retirement obligations as of December 31, 2019 and 2018 of $6 million and $5 million, respectively,
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. Refer to Note 11 for additional discussion regarding derivative
instruments. Cash flows related to derivative instruments that are designated in hedging relationships are
generally classified on the consolidated statements of cash flows in the same category as the cash flows
from the associated hedged item. 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.

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 and other risks. We
periodically evaluate our exposure to such risks and record liabilities for those matters when a loss is
considered probable and reasonably estimable. We reverse the liabilities recorded for those matters when
a loss is no longer considered probable. Our liabilities exclude any estimates for legal costs not yet incurred
associated with handling these matters. The adequacy of liabilities 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.

Leases — We enter into operating leases where we are the lessee, primarily for office facilities, equipment,
and storage facilities. When a contract contains a lease such that it conveys the right to control the use of
an identified asset for a period of time in exchange for consideration, we record and measure right-of-use
assets and lease liabilities at the present value of future lease payments. We calculate the present value
using our incremental borrowing rate, which is a secured interest rate based on the remaining lease term.
Our lease payments are substantially all fixed and, in some cases, escalate according to a schedule. We
account for office facility leases, which may have lease components and non-lease components, as a single
lease component. Short-term leases with an initial term of twelve months or less are not recorded on the
consolidated statements of financial position. We recognize expenses related to our operating lease
obligations on a straight-line basis over the term of the lease.

Revenues — Substantially all of our revenue from contracts with customers is generated from providing
transmission services to customers based on tariff rates, as approved by the FERC. Revenues from the
transmission of electricity are recognized 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 accrual or deferral 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

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to customers, we account for that event as the recovery or settlement of the associated regulatory asset or
regulatory liability, respectively. Refer to Note 6 under “Cost-Based Formula Rates with True-Up Mechanism”
and Note 4 under “Formula Rate True-Up” for a discussion of our revenue accounting under our cost-based
Formula Rates.

Share-Based Payment and Employee Share Purchase Plan — Under the terms of the 2017 Omnibus
Plan, we may grant long term incentive awards of PBUs and SBUs. The awards are classified as liability
awards based on the cash settlement feature. The award units earn dividend equivalents which are also
settled in cash at the end of the vesting period. 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.

We also have an Employee Share Purchase Plan which enables ITC employees to purchase shares of
Fortis common stock. Our cost of the plan is based on the value of our contribution, as additional compensation
to a participating employee, equal to 10% of an employee’s contribution up to a maximum annual contribution
of 1% of an employee’s base pay and an amount equal to 10% of all dividends payable by Fortis on the
Fortis shares allocated to an employee’s ESPP account.

Refer to Note 16 for additional discussion of the plans.

Comprehensive Income (Loss) — Comprehensive income (loss) is the change in common 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, 2019, we have not recognized any uncertain income tax positions.

We file our federal income tax returns as part of the FortisUS consolidated federal tax return starting with
the year ended December 31, 2016 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 return. We have historically filed federal income tax returns with the IRS and
continue to file with various state and city jurisdictions. Our prior consolidated federal tax returns are no
longer subject to U.S. federal tax examinations for tax years 2016 and earlier. State and city jurisdictions
that remain subject to examination range from tax years 2015 to 2018. 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 7 and 12 for additional discussion on income taxes and tax reform.

4. 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

Through our Regulated Operating Subsidiaries, we generate nearly all our revenue from providing electric
transmission services over our transmission systems. As independent transmission companies, our transmission
services are provided and revenues are received based on our tariffs, as approved by the FERC. 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

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revenues at our Regulated Operating Subsidiaries reflect changing operating 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.

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

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

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 $7 million,
$5 million and $6 million for the years ended December 31, 2019, 2018 and 2017, respectively.

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 6 for more information on our
Formula Rates.

5. ACCOUNTS RECEIVABLE

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

position:

(In millions)
Trade accounts receivable

Unbilled accounts receivable

Due from affiliates

Other

Total accounts receivable

6. REGULATORY MATTERS

2019

December 31,

2018

2017

2016

2 $

102

108

—

117 $

102 $

119 $

108

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

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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 19 for detail on ROE matters for our
MISO Regulated Operating Subsidiaries and "Incentive Adders for Transmission Rates" discussed in Note 6 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 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, 2019:

(In millions)

Net regulatory liabilities as of December 31, 2018

Net refund of 2017 revenue deferrals and accruals, including accrued interest

Net revenue accrual for the year ended December 31, 2019

Net accrued interest payable for the year ended December 31, 2019

Net regulatory assets as of December 31, 2019

Total

(52)

(2)

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)

Current regulatory assets

Non-current regulatory assets

Current regulatory liabilities

Non-current regulatory liabilities

Net regulatory assets (liabilities)

Incentive Adders for Transmission Rates

December 31,

2019

2018

12 $

(51)

(1)

3 $

(27)

(49)

(52)

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.

MISO Regulated Operating Subsidiaries

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reflecting the 25 basis point adder for independent transmission ownership in transmission rates in November
2018. Refunds of $7 million were primarily made in the fourth quarter of 2018 and were completed in the first
quarter of 2019. The MISO Regulated Operating Subsidiaries sought rehearing of the FERC’s October 18, 2018
order, and on July 18, 2019, the FERC denied the rehearing request. On September 11, 2019, the MISO Regulated
Operating Subsidiaries filed an appeal of the FERC’s order in the D.C. Circuit Court. On December 16, 2019, the
D.C. Circuit Court established a briefing schedule for the appeal. Initial briefs were filed on January 27, 2020 and
reply briefs are due to be filed in the second quarter of 2020. We do not expect the final resolution of this proceeding
to have a material adverse impact on our consolidated results of operations, cash flows or financial condition.

Based on the October 18, 2018 FERC order, the authorized incentive adders for the MISO Regulated Operating
Subsidiaries have been revised to include a 25 basis point adder for independent transmission ownership. Prior
to the October 18, 2018 FERC order, the adders for independent transmission ownership were 100 basis points
at each of ITCTransmission and METC and 50 basis points at ITC Midwest. For each of the years ended December
31, 2019, 2018 and 2017, the authorized incentive adders for the MISO Regulated Operating Subsidiaries included
a 50 basis point adder for RTO participation. See Note 19 for information regarding the MISO ROE Complaints
and the associated impact to the base ROE of our MISO Regulated Operating Subsidiaries.

ITC Great Plains

As of December 31, 2019, the authorized ROE used by ITC Great Plains is 12.16% and is 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.

Calculation of Accumulated Deferred Income Tax Balances in Projected Formula Rates

On June 21, 2018, the FERC issued an order initiating a proceeding and paper hearings, pursuant to Section
206 of the FPA, to examine the methodology used by a group of TOs, including ITCTransmission and ITC Midwest,
for calculating balances of ADIT in forward-looking Formula Rates. The FERC previously concluded that the two-
step averaging methodology for ADIT is no longer necessary to comply with IRS normalization rules in light of
IRS guidance issued in 2017. On August 27, 2018, our MISO Regulated Operating Subsidiaries submitted a filing
with the FERC under Section 205 of the FPA to eliminate the use of the two-step averaging methodology in the
calculation of ADIT balances for the projected test year and modify the manner by which they calculate average
ADIT balances in their annual transmission Formula Rate true-up calculation, subject to receiving guidance from
the IRS to respond to the FERC order. On April 10, 2019, our MISO Regulated Operating Subsidiaries received
formal guidance from the IRS, which we believe is consistent with the filings that have been made to date in these
proceedings.

On December 20, 2018, the FERC issued an order that ITCTransmission and ITC Midwest make a compliance
filing to implement the changes to their Formula Rate templates and formally instituted a proceeding against METC
pursuant to Section 206 of the FPA to implement the changes. On May 16, 2019, the FERC issued an order
accepting in part and rejecting in part ITCTransmission’s and ITC Midwest’s January 22, 2019 compliance filing
and ordered them to make another compliance filing within 30 days of the date of the order. Specifically, the FERC
accepted the portion of the compliance filing that removed the two-step averaging methodology, but rejected the
compliance filing insofar as it carried proration to the Formula Rate true-up calculation because the FERC found
that was beyond the scope of its previous orders in the docket. Additionally, on May 16, 2019, the FERC issued

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an order rejecting the January 22, 2019 METC filing pursuant to Section 205 of the FPA as it requested a retroactive
effective date and ordered METC to make a compliance filing in the proceeding pursuant to Section 206 of the
FPA within 30 days of the date of the order. The FERC noted in the METC order that the compliance filing should
only remove the two-step averaging methodology and should not carry proration to the calculation of the Formula
Rate true-up. On June 17, 2019, our MISO Regulated Operating Subsidiaries made compliance filings consistent
with the FERC orders, and on August 21, 2019, the FERC issued orders accepting those compliance filings. On
October 1, 2019, our MISO Regulated Operating Subsidiaries, along with other MISO TOs, submitted a filing with
the FERC pursuant to Section 205 of the FPA to carry proration to the calculation of the Formula Rate true-up,
and on November 19, 2019, the FERC accepted the filing. We do not expect the resolution of these proceedings
to have a material adverse impact on our consolidated results of operations, cash flows or financial condition.

Rate of Return on Equity Complaints

See “Rate of Return on Equity Complaints” in Note 19 for a discussion of the MISO ROE Complaints.

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7. REGULATORY ASSETS AND LIABILITIES

Regulatory Assets

The following table summarizes the regulatory asset balances:

(In millions)
Regulatory Assets:

Current:

December 31,

2019

2018

Revenue accruals (including accrued interest of $1 and less than $1 as of

December 31, 2019 and 2018, respectively) (a)

12 $

Total current

Non-current:

Revenue accruals (including accrued interest of $1 and less than $1 as of

December 31, 2019 and 2018, respectively) (a)

ITCTransmission ADIT deferral (net of accumulated amortization of $51 and $48

as of December 31, 2019 and 2018, respectively)

METC ADIT deferral (net of accumulated amortization of $31 and $29 as of

December 31, 2019 and 2018, respectively)

METC regulatory deferrals (net of accumulated amortization of $10 and $9 as of

December 31, 2019 and 2018, respectively)

Income taxes recoverable related to AFUDC equity

ITC Great Plains start-up, development and pre-construction (net of accumulated
amortization of $6 and $5 as of December 31, 2019 and 2018, respectively)

Pensions and postretirement

Income taxes recoverable related to implementation of the Michigan Corporate

Income Tax and other state excess deficient taxes

Accrued asset removal costs

Total non-current

Total

____________________________

229

241 $

200

212

(a) Refer to discussion of revenue accruals in Note 6 under “Cost-Based Formula Rates with True-Up Mechanism.”
Our Regulated Operating Subsidiaries do not earn a return on the balance of these regulatory assets, but do
accrue interest carrying costs, which are subject to rate recovery along with the principal amount of the revenue
accrual.

ITCTransmission ADIT Deferral

The carrying amount of the ITCTransmission ADIT Deferral is the remaining unamortized balance of the portion
of ITCTransmission’s purchase price in excess of fair value of net assets acquired from DTE Energy approved for
inclusion in future rates by the FERC. The original amount recorded for this regulatory asset of $61 million is
recognized in rates and amortized on a straight-line basis over 20 years beginning March 1, 2003. ITCTransmission
includes the remaining unamortized balance of this regulatory asset in rate base. ITCTransmission recorded
amortization expense of $3 million annually during 2019, 2018 and 2017, which is included in depreciation and
amortization in our consolidated statements of comprehensive income and recovered through ITCTransmission’s
cost-based Formula Rate template.

METC ADIT Deferral

The carrying amount of the METC ADIT Deferral is the remaining unamortized balance of the portion of METC’s
purchase price in excess of the fair value of net assets acquired at the time MTH acquired METC from Consumers
Energy approved for inclusion in future rates by the FERC. The original amount approved for recovery recorded
for this regulatory asset of $43 million is recognized in rates and amortized on a straight-line basis over 18 years
beginning January 1, 2007. METC includes the remaining unamortized balance of this regulatory asset in rate

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base. METC recorded amortization expense of $2 million annually during 2019, 2018 and 2017, which is included
in depreciation and amortization in our consolidated statements of comprehensive income and recovered through
METC’s cost-based Formula Rate template.

METC Regulatory Deferrals

The carrying amount of the METC Regulatory Deferrals is the amount METC has deferred, as a regulatory
asset, of depreciation and related interest expense associated with new transmission assets placed in service
from January 1, 2001 through December 31, 2005 that were included on METC’s balance sheet at the time MTH
acquired METC from Consumers Energy. The original amount recorded for this regulatory asset of $15 million,
and approved for inclusion in future rates by the FERC, is recognized in rates and amortized over 20 years beginning
January 1, 2007. METC includes the remaining unamortized balance of this regulatory asset in rate base. METC
recorded amortization expense of $1 million annually during 2019, 2018 and 2017, which is included in depreciation
and amortization in our consolidated statements of comprehensive income and recovered through METC’s cost-
based Formula Rate template.

Income Taxes Recoverable Related to AFUDC Equity

Accounting standards for income taxes provide that a regulatory asset be recorded if it is probable that a future
increase in taxes payable, relating to the book depreciation of AFUDC equity that has been capitalized to property,
plant and equipment, will be recovered from customers through future rates. The regulatory asset for the tax effects
of AFUDC equity is recovered over the life of the underlying book asset in a manner that is consistent with the
depreciation of the AFUDC equity that has been capitalized to property, plant and equipment. This regulatory asset
and the related offsetting deferred income tax liabilities do not affect rate base.

ITC Great Plains Start-Up, Development and Pre-Construction

In 2013, ITC Great Plains made a filing with the FERC, under Section 205 of the FPA, to recover start-up,
development and pre-construction expenses in future rates. These expenses included certain costs incurred by
ITC Great Plains for two regional cost sharing projects in Kansas prior to construction. In March 2015, FERC
accepted ITC Great Plains’ request to commence amortization of the authorized regulatory assets, subject to
refund, and set the matter for hearing and settlement judge procedures. In December 2015, the FERC issued an
order accepting an uncontested settlement agreement establishing the amounts of the regulatory assets and
associated carrying charges to be recovered. ITC Great Plains includes the unamortized balance of these
regulatory assets in rate base and will amortize them over a 10-year period, beginning in the second quarter of
2015. The amortization expense is recorded to general and administrative expenses in our consolidated statements
of comprehensive income and recovered through ITC Great Plains’ cost-based Formula Rate.

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 charged and/or credited to AOCI to be recorded as a regulatory asset
or liability. As the unrecognized amounts recorded to this regulatory asset are recognized, expenses will be
recovered from customers in future rates under our cost based Formula Rates. This regulatory asset is not included
when determining rate base.

Income Taxes Recoverable Related to Implementation of the Michigan Corporate Income Tax

Under the Michigan Corporate Income Tax, we are taxed at a rate of 6.0% on federal taxable income attributable
to our operations in the state of Michigan, subject to certain adjustments. In 2011, due to certain Michigan tax law
changes we were required to establish new deferred income tax balances under the Michigan Corporate Income
Tax, and the net result was incremental deferred state income tax liabilities at both ITCTransmission and METC.
Under our cost-based Formula Rate, the future tax receivable as a result of the tax law change has resulted in the
recognition of a regulatory asset, which will be collected from customers for the 23-year period and the 32-year
period for ITCTransmission and METC, respectively, beginning in 2016. ITCTransmission and METC include this
regulatory asset within deferred taxes for rate-making purposes when determining rate base.

Accrued Asset Removal Costs

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asset and removal costs incurred are added to this regulatory asset. In addition, this regulatory asset has also
been adjusted for timing differences between incurred costs to settle legal asset retirement obligations and the
recognition of such obligations under the standards set forth by the FASB. Our Regulated Operating Subsidiaries
include this item, excluding the cost component related to the recognition of our legal asset retirement obligations
under the standards set forth by the FASB, as a reduction to accumulated depreciation for rate-making purposes,
when determining rate base.

Regulatory Liabilities

The following table summarizes the regulatory liability balances:

(In millions)
Regulatory Liabilities:

Current:

December 31,

2019

2018

Revenue deferrals (including accrued interest of $4 and $2 as of December 31,

2019 and 2018, respectively) (a)

51 $

Refund liability related to return on equity complaints (including accrued interest of

$6 and $18 as of December 31, 2019 and 2018, respectively) (b)

Estimated refund related to ITC Great Plains incentive adder complaint (c)

Total current

Non-current:

Revenue deferrals (including accrued interest of less than $1 and $1 as of

December 31, 2019 and 2018, respectively) (a)

Accrued asset removal costs

Excess state income tax deductions

Income taxes refundable related to implementation of the TCJA

Total non-current

Total

____________________________

123

509

584

151

—

178

511

640

707 $

818

(a) Refer to discussion of revenue deferrals in Note 6 under “Cost-Based Formula Rates with True-Up Mechanism.”
Our Regulated Operating Subsidiaries accrue interest on the true-up amounts which will be refunded through
rates along with the principal amount of revenue deferrals in future periods.

(b) Refer to discussion of the refund liability in Note 19 under “Rate of Return on Equity Complaints.”

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 portion
of depreciation expense included in our depreciation rates related to asset removal costs is added to this regulatory
liability and removal expenditures incurred are charged to this regulatory liability. Our Regulated Operating
Subsidiaries include this item within accumulated depreciation for rate-making purposes and determining rate
base.

Excess State Income Tax Deductions

We have taken state income tax deductions associated with property additions that exceed the tax basis of
property, and the unrealized income tax benefits resulting from these deductions are expected to be refunded to
customers through future rates when the income tax benefits are realized. This regulatory liability is included within
deferred taxes for rate-making purposes when determining rate base.

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Income Taxes Refundable Related to Implementation of the TCJA

In December 2017, the President of the United States signed into law the TCJA, which enacted significant
changes to the Internal Revenue Code including a reduction in the U.S. federal corporate income tax rate from
35% to 21% effective for tax years beginning after 2017. The Company was required to revalue its deferred tax
assets and liabilities at the new federal corporate income tax rate as of the date of the enactment of the TCJA,
which resulted in lower net deferred tax liabilities and the establishment of a regulatory liability for excess deferred
taxes at our Regulated Operating Subsidiaries. The excess deferred taxes are generally the result of accelerated
federal tax deductions realized by our Regulated Operating Subsidiaries in periods when the U.S. federal corporate
income tax rate was 35% and now would be returned to customers in a period where the U.S. federal corporate
income tax rate is 21%. As the excess deferred taxes must be returned to customers this regulatory liability is
recognized. For our Regulated Operating Subsidiaries, our deferred taxes are subject to a normalization method
of accounting for the excess tax reserves resulting from the change in the federal statutory tax rate which involves
the use of ARAM for the determination of the timing of the return of the excess deferred taxes to customers
associated with public utility property. In addition, a portion of our excess deferred taxes at our Regulated Operating
Subsidiaries are associated with other types of deferred taxes that are not related to public utility property and are
subject to amortization. We have elected to amortize these excess deferred taxes using RSGM and have determined
that it is a reasonable method of amortization. During the years ended December 31, 2019 and 2018, we recorded
$1 million and less than $1 million, respectively, of amortization related to the excess deferred taxes under ARAM
and RSGM. The net regulatory liability is included within deferred taxes for rate-making purposes when determining
rate base.

8. PROPERTY, PLANT AND EQUIPMENT

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

(In millions)
Property, plant and equipment

Regulated Operating Subsidiaries:

Property, plant and equipment in service

Construction work in progress

Capital equipment inventory

Other

ITC Holdings and other

Total

Less: Accumulated depreciation and amortization

Property, plant and equipment, net

December 31,

2019

2018

9,973 $

375

10,512

(1,930)

8,582 $

9,113

465

9,689

(1,779)

7,910

Additions to property, plant and equipment in service and construction work in progress during 2019 and 2018
were due primarily to asset acquisitions and projects to upgrade or replace existing transmission plant 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.

9. GOODWILL AND INTANGIBLE ASSETS

Goodwill

At December 31, 2019 and 2018, we had goodwill balances recorded at ITCTransmission, METC and ITC
Midwest of $173 million, $454 million and $323 million, respectively, which resulted from the ITCTransmission and
METC acquisitions and ITC Midwest’s acquisition of the IP&L transmission assets, respectively.

Intangible Assets

Pursuant to the METC acquisition in October 2006, we have identified intangible assets with finite lives derived
from the portion of regulatory assets recorded on METC’s historical FERC financial statements that were not
recorded on METC’s historical GAAP financial statements associated with the METC Regulatory Deferrals and

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the METC ADIT Deferral as described in Note 7. The carrying amounts of the intangible asset for the METC
Regulatory Deferrals and the METC ADIT Deferral were $14 million and $5 million (net of accumulated amortization
of $26 million and $14 million), respectively, as of December 31, 2019, and $16 million and $6 million (net of
accumulated amortization of $24 million and $13 million), respectively, as of December 31, 2018. The amortization
periods for the METC Regulatory Deferrals and the METC ADIT Deferral are 20 years and 18 years, respectively,
beginning January 1, 2007. METC earns an equity return on the remaining unamortized balance of both intangible
assets and recovers the amortization expense through METC’s cost-based Formula Rate template.

ITC Great Plains has recorded intangible assets for payments made by and obligations of ITC Great Plains to
certain TOs to acquire rights, which are required under the SPP tariff to designate ITC Great Plains to build, own
and operate projects within the SPP region, including three regional cost sharing projects in Kansas. The carrying
amount of these intangible assets was $14 million (net of accumulated amortization of $2 million) as of December 31,
2019 and 2018. The amortization period for these intangible assets is 50 years, beginning March 31, 2011.

We recognized $3 million, $4 million, and $3 million of amortization expense of our intangible assets during the
years ended December 31, 2019, 2018 and 2017, respectively, recorded in depreciation and amortization on the
consolidated statements of comprehensive income. We expect the annual amortization of our intangible assets
that have been recorded as of December 31, 2019 to be as follows:

(In millions)
2020

2021

2022

2023

2024

2025 and thereafter

Total

10. LEASES

Operating lease costs for the year ended December 31, 2019 were $1 million. The following table shows the
undiscounted future minimum lease payments under our operating leases at December 31, 2019 reconciled to the
corresponding discounted lease liabilities presented in our consolidated financial statements:

Future Minimum Lease Payments

(in millions)

2020

2021

2022

2023

2024

2025 and beyond

Total lease payments

Difference between undiscounted cash flows and discounted cash flows

Present value of lease liabilities

Less: Current operating lease liabilities

Noncurrent operating lease liabilities

Leases are presented in the consolidated statements of financial position as follows:

(in millions)
Operating Lease Assets

Current Operating Lease Liabilities

Noncurrent Operating Lease Liabilities

Classification

Other assets

Other current liabilities

Other liabilities

December 31, 2019

—

(1)

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Disclosures Related to Periods Prior to Adoption of the New Lease Guidance

Operating lease costs for the year ended December 31, 2018 were $1 million. Undiscounted future minimum

lease payments under the operating leases at December 31, 2018 were as follows:

Future Minimum Lease Payments

(in millions)

2019

2020

2021

2022

2023 and thereafter

Total minimum lease payments

Supplementary Lease Information

Weighted-average remaining lease term (years)

Weighted-average discount rate

—

December 31, 2019

4.9

4.0%

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11. 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)

ITC Holdings 6.375% Senior Notes, due September 30, 2036

ITC Holdings 5.50% Senior Notes, due January 15, 2020

ITC Holdings 4.05% Senior Notes, due July 1, 2023

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

ITC Holdings 3.35% Senior Notes, due November 15, 2027

ITC Holdings Term Loan Credit Agreement, due June 11, 2021

ITC Holdings Revolving Credit Agreement, due October 21, 2022 (b)

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 Revolving Credit Agreement, due October 21, 2022 (b)

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 Revolving Credit Agreement, due October 21, 2022 (b)

ITC Midwest 6.15% First Mortgage Bonds, Series A, due January 31, 2038

ITC Midwest 7.27% First Mortgage Bonds, Series C, due December 22, 2020 (a)

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 Revolving Credit Agreement, due October 21, 2022 (b)

ITC Great Plains 4.16% First Mortgage Bonds, Series A, due November 26, 2044

ITC Great Plains Revolving Credit Agreement, due October 21, 2022 (b)

Total principal

Unamortized deferred financing fees and discount

Total debt

____________________________

December 31,

2019

2018

200

—

250

400

300

400

500

200

100

285

100

225

150

200

175

100

225

200

175

130

150

200

250

400

300

400

500

—

100

285

100

225

—

150

200

—

175

100

225

200

175

150

5,844

(37)

5,807

5,378

(40)

5,338

(a) As of December 31, 2019 there was $235 million of debt included within debt maturing within one year and
classified as a current liability in the consolidated statements of financial position. As of December 31, 2018
we had no debt maturing within one year.

(b) On January 10, 2020 we extended the maturity date of our revolving credit agreements to October 20, 2023.

See below in “Revolving Credit Agreement Amendments” for more details.

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The annual maturities of debt as of December 31, 2019 are as follows:

(In millions)
2020

2021

2022

2023

2024

2025 and thereafter

Total

ITC Holdings

Term Loan Credit Agreement

235

200

799

250

475

3,885

5,844

On June 12, 2019, ITC Holdings entered into an unsecured, unguaranteed $400 million term loan credit
agreement with a maturity date of June 11, 2021, under which ITC Holdings borrowed $200 million. The proceeds
were used for the early redemption of the $200 million 5.50% Senior Notes due January 15, 2020. In January
2020, ITC Holdings drew upon the remaining $200 million under the term loan credit agreement to repay outstanding
commercial paper balances. The weighted-average interest rate on the borrowing outstanding under this agreement
was 2.4% at December 31, 2019.

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, 2019,
ITC Holdings had $200 million of commercial paper, issued and outstanding under the program, with a weighted-
average interest rate of 2.2% and weighted average remaining days to maturity of 12 days. The amount outstanding
as of December 31, 2019 was classified as debt maturing within one year in the consolidated statements of financial
position. As of December 31, 2018, ITC Holdings did not have any commercial paper issued or outstanding.

ITCTransmission

First Mortgage Bonds

On August 28, 2019, ITCTransmission issued $75 million aggregate principal amount of 3.30% First Mortgage
Bonds, due August 28, 2049. The proceeds were used to repay existing indebtedness under the revolving credit
agreement and will also be used to partially fund capital expenditures and for general corporate purposes. All of
ITCTransmission’s First Mortgage bonds are issued under its First Mortgage and Deed of Trust and secured by a
first mortgage lien on substantially all of its real property and tangible personal property.

On March 29, 2018, ITCTransmission issued $225 million aggregate principal amount of 4.00% First Mortgage
Bonds due March 30, 2053. The proceeds were used to refinance $100 million of ITCTransmission’s 5.75% First
Mortgage Bonds due April 1, 2018 and repay the existing indebtedness under ITCTransmission’s revolving credit
agreement in March 2018. Proceeds were also used to repay ITCTransmission’s $50 million of borrowings under
its term loan credit agreement due March 23, 2019. Remaining proceeds were used to partially fund capital
expenditures and for general corporate purposes. ITCTransmission’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.

METC

Senior Secured Notes

On January 15, 2019, METC issued $50 million of 4.55% Senior Secured Notes, due January 15, 2049. On
July 10, 2019, METC issued an additional $50 million of Senior Secured Notes at 4.65% with terms and conditions
identical to those of the 4.55% Senior Secured Notes except the interest rate which includes a 10 basis point
premium and the due date which is 30 years from the date of the issuance. The proceeds from both issuances
were used to repay borrowings under the METC revolving credit agreement, to partially fund capital expenditures

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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.

Term Loan Credit Agreement

On January 23, 2020, METC entered into an unsecured, unguaranteed term loan credit agreement, due January
23, 2021, under which METC borrowed the maximum of $75 million available under the agreement. The proceeds
were used for general corporate purposes, primarily the repayment of borrowings under the METC revolving credit
agreement.

ITC Midwest

First Mortgage Bonds

On November 1 and November 2, 2018, ITC Midwest issued an aggregate of $175 million of 4.32% First
Mortgage Bonds due November 1, 2051. The proceeds were used to partially repay existing indebtedness under
the ITC Midwest revolving credit agreement, partially fund capital expenditures and for general corporate purposes.
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 our real property and tangible personal property.

Derivative Instruments and Hedging Activities

We have entered into interest rate swaps to manage interest rate risk associated with the anticipated refinancing
of the $400 million term loan at ITC Holdings with a maturity date of June 11, 2021. At December 31, 2019, ITC
Holdings had the following interest rate swaps:

Interest Rate Swaps
(in millions, except percentages)

Notional
Amount

Weighted Average
Fixed Rate

July 2019 swap

August 2019 swap

October 2019 swaps

Total

100

200

1.816%

1.488%

1.288%

Original Term
5 years

5 years

Effective Date
November 2020

November 2020

The 5-year term interest rate swaps call for ITC Holdings to receive interest quarterly at a variable rate equal
to LIBOR and to pay interest semi-annually at various fixed rates effective for the 5-year period beginning November
15, 2020. The agreements include a mandatory early termination provision and will be terminated no later than
the effective date of the interest rate swaps of November 15, 2020. The interest rate swaps do not contain credit-
risk-related contingent features. The interest rate swaps are highly effective at offsetting changes in the forecasted
interest cash flows associated with the debt issuance, resulting from changes in benchmark interest rates from
the trade date of the interest rate swaps to the issuance date of the debt obligation.

In January 2020, ITC Holdings entered into three 5-year interest rate swap contracts with fixed rates of 1.551%,
1.447% and 1.314%, and each with a notional amount of $63 million and effective date of October 1, 2020. The
interest rate swaps also manages interest rate risk associated with the refinancing of the $400 million term loan
at ITC Holdings. The agreements include a mandatory early termination provision and will be terminated no later
than the effective date of the interest rate swaps of October 1, 2020. The interest rate swaps are expected to be
highly effective at offsetting changes in the fair value of the forecasted interest cash flows associated with the debt
issuance, resulting from changes in benchmark interest rates from the trade date of the interest rate swaps to the
issuance date of the debt obligation.

The interest rate swaps qualify for cash flow hedge accounting treatment, whereby any gain or loss recognized
from the trade date to the effective date is recorded net of tax in AOCI. As of December 31, 2019, the fair value of
the derivative instruments of $3 million was recorded in other current assets in the consolidated statements of
financial position. Refer to Note 14 for additional fair value information.

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Revolving Credit Agreements

At December 31, 2019, ITC Holdings and certain of its Regulated Operating Subsidiaries had the following

unsecured revolving credit facilities available:

(In millions, except percentages)
ITC Holdings

ITCTransmission

METC

ITC Midwest

ITC Great Plains

Total

____________________________

Total
Available
Capacity

Outstanding
Balance (a)

Unused
Capacity

400 $

34 $

366 (d)

100

225
75

130

900 $

299 $

601

Weighted
Average
Interest Rate
on
Outstanding
Balance (b)
2.9%

2.6%

Commitment
Fee Rate (c)
0.175%

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.

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
$166 million as of December 31, 2019.

Revolving Credit Agreement Amendments

On January 10, 2020, ITC Holdings, ITCTransmission, METC, ITC Midwest and ITC Great Plains amended
and restated their respective revolving credit agreements each dated October 23, 2017. The amendments extend
the maturity date of the revolving credit agreements from October 2022 to October 2023. The determination of the
applicable interest rates and commitment fee rates in the new agreements is consistent with the previous
agreements as described above and remain subject to adjustment based on the borrower’s credit rating.

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12. INCOME TAXES

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)
Income tax expense at federal statutory rate (a)

State income taxes (net of federal benefit) (b)

AFUDC equity

Revaluation of deferred federal income taxes (c)

Other, net (d)

Total income tax provision

____________________________

Year Ended December 31,

2019

2018

2017

118 $

93 $

(5)

—

(3)

(6)

(2)

(5)

180

(10)

132 $

111 $

196

(a) The federal statutory rate is 21% for 2019 and 2018, and 35% for 2017.

(b) Amounts for the years ended December 31, 2019 and 2018 includes $1 million and $6 million, respectively,
related to the remeasurement of Iowa NOLs due to the rate change from 12.0% to 9.8% effective January 1,
2021. Amount for the year ended December 31, 2017 includes income tax benefits of $3 million related to the
revaluation of state deferred tax assets and liabilities for the net of federal benefit impact of the TCJA.

(c) Amount for the year ended December 31, 2018 represents the change in estimate related to the TCJA
remeasurement recorded in 2017 based on the ITC Holdings’ 2017 Federal Tax return filed. Amount for the
year ended December 31, 2017 represents income tax expense related to the revaluation of federal deferred
tax assets and liabilities as a result of the TCJA.

(d) Amount for the year ended December 31, 2017 includes income tax expense of $1 million related to the
establishment of a valuation allowance for the portion of a capital loss expected to not be utilized before
expiration.

Components of the income tax provision were as follows:

(In millions)
Current income tax (benefit) expense

Deferred income tax expense (a)

Total income tax provision

____________________________

Year Ended December 31,

2019

2018

2017

(3) $

135

4 $

107

132 $

111 $

195

196

(a) Amount for the year ended December 31, 2017 includes income tax expense of $5 million related to the net
revaluation of federal and state deferred tax assets and liabilities at ITC Holdings as a result of the TCJA.

Deferred tax assets and liabilities are recognized for the estimated future tax effect of temporary differences

between the tax basis of assets or liabilities and the reported amounts in the consolidated financial statements.

The TCJA resulted in significant changes to the Internal Revenue Code including a reduction in the U.S. federal
corporate income tax rate from 35% to 21% effective for tax years beginning after 2017. For additional information
on the impacts of tax reform, see Note 7. During the year ended December 31, 2018, Iowa enacted a reduction
in corporate statutory income tax rates from 12.0% to 9.8%, effective January 1, 2021. Based upon the future
change in rate, we revalued the Iowa NOL at ITC Holdings. As a result, additional income tax expense was recorded
for the year ended December 31, 2018 compared to the same period in 2019. For the years ended December 31,
2019 and 2018, our effective tax rates were 23.6% and 25.2%, respectively.

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

(In millions)
Property, plant and equipment

Federal income tax NOLs and other credits

METC regulatory deferral (a)

Acquisition adjustments — ADIT deferrals (a)

Goodwill

Refund liabilities (a)

Regulatory liability gross up — TCJA

Pension and postretirement liabilities

State income tax NOLs (net of federal benefit)

True-up adjustment principal & interest

Other, net

Net deferred tax liabilities

Gross deferred income tax liabilities

Gross deferred income tax assets

Net deferred tax liabilities

____________________________

(a) Described in Note 7.

December 31,

2019

2018

(1,071) $

(884)

117

(5)

(7)

(133)

134

(1)

(6)

(8)

(128)

138

(873) $

(721)

(1,233) $

(1,040)

360

(873) $

319

(721)

We have federal income tax NOLs as of December 31, 2019. We expect to use our NOLs prior to their expirations
starting in 2036. We also have state income tax NOLs as of December 31, 2019, all of which we expect to use
prior to their expiration starting in 2022.

13. 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 contribute additional amounts
as necessary to meet the minimum funding requirements of the Employee Retirement Income Security Act of 1974,
or as we deem appropriate. We made contributions of $4 million to the retirement plan in each of 2019, 2018, and
2017. We expect to contribute $4 million to the retirement plan in 2020.

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 $54 million and $53 million at December 31,
2019 and 2018, 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 years ended December 31,
2019, 2018, and 2017, we contributed $1 million, $3 million, and $14 million, respectively, 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 $9 million, $9 million, and $8 million to the postretirement benefit plan
in 2019, 2018, and 2017, respectively. We expect to contribute $11 million to the postretirement benefit plan in 2020.

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Net periodic benefit costs by component for the pension plans and postretirement benefit plan were as follows:

(In millions)
Service cost

Interest cost

Expected return on plan assets

Amortization of unrecognized loss

Net benefit cost

Pension Plans

Years Ended December 31,

Postretirement Benefit Plan

Years Ended December 31,

2019

2018

2017

2019

2018

2017

7 $
5
(5)
1
8 $

7 $
4

(5)
1
7 $

6 $

9 $

10 $

(4)

—

(3)

—

7 $

9 $

10 $

(2)

—

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)
Change in Benefit Obligation:

Beginning projected benefit obligation

Service cost

Interest cost

Actuarial net gain (loss)

Benefits paid

Ending projected benefit obligation

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

Accumulated benefit obligation:

Retirement plan

Supplemental benefit plans

Total accumulated benefit obligation

Amounts recorded as:

Funded Status:

Accrued pension and postretirement liabilities

Other non-current assets

Other current liabilities

Total

Unrecognized Amounts in Non-current Regulatory
Assets:

Net actuarial loss

Total

Pension Plans

December 31,

Postretirement Benefit Plan

December 31,

2019

2018

2019

2018

(123)
(7)

(5)

(12)
6
(141)

16
4

(2)

(50)

(78)

(57)
(135)

(55)
9

(4)

(127)

(90)

(7)

(4)

(123)

(3)

(9)

(4)

(11)

(113)

(1)

(50)

(18)

(67)

(52)

N/A

(119)

— $

(50)

(18)

(4)

N/A

(50)

(18)

(86)

(10)

(3)

(90)

(2)

(1)

(18)

N/A

—

(18)

N/A

(18)

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 on our consolidated
statements of financial position, as discussed in Note 7. The amounts recorded as a regulatory asset represent a
net periodic benefit cost to be recognized in our operating income in future periods. Our measurement of the

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accumulated benefit obligation for the postretirement benefit plan as of December 31, 2019 and 2018 does not reflect
the potential receipt of any subsidies under the Medicare Prescription Drug, Improvement and Modernization Act of
2003.

The net actuarial gain for the year ended December 31, 2018 and the net actuarial loss for the year ended
December 31, 2019 within the change in benefit obligation are primarily the result of fluctuations in the discount rates
for both the Pension Plans and Postretirement Benefit Plan.

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)
Projected benefit obligation

Fair value of plan assets (a)

____________________________

Pension Plans

December 31,

2019

2018

(59) $

—

(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.

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)
Accumulated benefit obligation

Fair value of plan assets (a)

____________________________

Pension Plans

December 31,

2019

2018

(57) $

—

(52)

—

(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,

Postretirement Benefit Plan

December 31,

2019
3.27%

4.00%

N/A

2018
4.28%

4.50%

4.00%

N/A

2017
3.57%

4.50%

4.00%

N/A

2019
3.61%

N/A

4.00%

6.25%

5.00%

2025

2018
4.47%

N/A

4.00%

6.50%

5.00%

2025

2017
3.75%

N/A

4.00%

6.75%

5.00%

2025

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

Years Ended December 31,

Weighted average discount rate — service cost

2019
4.42%

Weighted average discount rate — interest cost

3.99%

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

4.50%

4.00%

N/A

2018
3.70%

3.26%

4.50%

4.00%

N/A

2017
4.20%

3.45%

4.50%

4.00%

N/A

2019
4.58%

4.28%

N/A

4.00%

6.50%

5.00%

2025

2018
3.80%

3.58%

N/A

4.00%

6.75%

5.00%

2025

2017
4.35%

3.98%

N/A

4.00%

7.00%

5.00%

2022

Expected long-term rate of return on plan assets 6.60%

6.40%

6.20%

5.00%

4.90%

4.70%

At December 31, 2019, the projected benefit payments for the pension plans and postretirement benefit plan
calculated using the same assumptions as those used to calculate the benefit obligations described above are as
follows:

(In millions)
2020

2021

2022

2023

2024

2025 through 2029

Pension Plans

Postretirement
Benefit Plan

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, 2019 and 2018, 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
2019

50.0%
50.0%
100.0%

Pension Plans

Postretirement Benefit Plan

2019
50.0%

50.0%

2018
48.6%

51.4%

2019
50.0%

50.0%

2018
48.4%

51.6%

100.0%

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.

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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, 2019 and 2018, there were no transfers
between levels.

The fair value measurement of the retirement plan assets was as follows:

(In millions)
Financial assets measured on a recurring basis:

Mutual funds — U.S. equity securities

Mutual funds — international equity securities

Mutual funds — fixed income securities

Total

December 31, 2019
Fair Value Measurements at
Reporting Date Using
Level 2

Level 1

Level 3

Level 1

December 31, 2018
Fair Value Measurements at
Reporting Date Using
Level 2

Level 3

36 $

— $

30 $

— $

46
91 $

—

— $

73 $

— $

—

The fair value measurement of the postretirement benefit plan assets was as follows:

(In millions)
Financial assets measured on a recurring basis:

Mutual funds — U.S. equity securities

Mutual funds — international equity securities

Mutual funds — fixed income securities

Total

December 31, 2019
Fair Value Measurements at
Reporting Date Using

December 31, 2018
Fair Value Measurements at
Reporting Date Using

Level 1

Level 2

Level 3

Level 1

Level 2

Level 3

45 $

— $

36 $

— $

48
95 $

—

— $

72 $

— $

—

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 $5 million in each of 2019, 2018, and
2017.

14. 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, 2019 and 2018, there were no transfers
between levels.

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Our assets measured at fair value subject to the three-tier hierarchy at December 31, 2019, were as follows:

(in millions)
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

Significant
Other Observable
Inputs

Significant
Unobservable
Inputs

(Level 1)

(Level 2)

(Level 3)

50 $

— $

—

58 $

3 $

—

Our assets measured at fair value subject to the three-tier hierarchy at December 31, 2018, were as follows:

(in millions)
Financial assets measured on a recurring basis:

Cash equivalents

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

Significant
Other Observable
Inputs

Significant
Unobservable
Inputs

(Level 1)

(Level 2)

(Level 3)

1 $

49
5

55 $

— $
—
—
— $

—
—
—
—

As of December 31, 2019 and 2018, we held certain assets that are required to be measured at fair value on
a recurring basis. The assets included in the table 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 13. 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 earnings.

The assets related to derivatives consist of interest rate swaps discussed in Note 11. The fair value of our
interest rate swap derivatives is determined based on a DCF method using LIBOR 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, 2019 and 2018. Refer to Note 9 for
additional information on our goodwill and intangible assets.

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 and term loan credit agreements and commercial paper,
was $5,672 million and $5,186 million at December 31, 2019 and 2018, 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 and term
loan credit agreements and commercial paper, was $5,108 million and $5,130 million at December 31, 2019 and
2018, respectively.

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Revolving and Term Loan Credit Agreements

At December 31, 2019 and 2018, we had a consolidated total of $499 million and $208 million, respectively,
outstanding under our revolving and term loan 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.

15. STOCKHOLDER'S EQUITY

Accumulated Other Comprehensive Income

The following table provides the components of changes in AOCI:

(In millions)
Balance at the beginning of period

Year Ended December 31,

2019

2018

2017

4 $

2 $

Reclassification of deferred tax effects on interest rate cash flow hedges

stranded in AOCI, subject to the TCJA, into retained earnings

—

Other Comprehensive Income

Derivative Instruments

Reclassification of net loss relating to interest rate cash flow hedges from
AOCI to earnings (net of tax of less than $1 for each of the years ended
December 31, 2019 and 2018 and $1 for the year ended December
31, 2017) (a)

Gain (loss) on interest rate swaps relating to interest rate cash flow
hedges (net of tax of $1 for each of the years ended December 31,
2019 and 2017)

Total other comprehensive income (loss), net of tax

Balance at the end of period

____________________________

—

7 $

4 $

—

(1)

—

(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 loss relating to interest rate cash flow hedges to be reclassified from AOCI to earnings for
the 12-month period ending December 31, 2020 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.

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16. SHARE-BASED COMPENSATION AND EMPLOYEE SHARE PURCHASE PLAN

We recorded share-based compensation costs as follows:

(In millions)
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

2017 Omnibus Plan

Year Ended December 31,

2019

2018

2017

2 $

1 $

40 $

11 $

8 $

4 $

Under the 2017 Omnibus Plan, we may grant long-term incentive awards of PBUs and SBUs to employees,
including executive officers, of ITC Holdings and its subsidiaries. Each PBU and SBU granted will be 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. The awards vest on the date specified in a particular grant agreement, provided the service and
performance criteria, as applicable, are satisfied.

Performance-Based Units

The PBUs are classified as liability awards based on the cash settlement feature. 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. The granted awards and related dividend equivalents
have no shareholder rights. PBUs that were granted pursuant to the 2017 Omnibus Plan generally vest on the third
December 31st following the grant date, provided the service and performance criteria are satisfied and will be settled
during the subsequent quarter.

The following table shows the changes in PBUs during the year ended December 31, 2019:

PBUs at December 31, 2018

Granted

Forfeited

PBUs at December 31, 2019

Number of
Performance
Based Units

637,551

380,305

(41,628)

976,228

The following table presents the classification in the consolidated statements of financial position of obligations

related to outstanding PBUs not yet settled:

(In millions)
Accrued compensation

Other long-term liabilities

Total

December 31,

2019

2018

17 $

36 $

—

The aggregate fair value of PBUs as of December 31, 2019 and 2018 was $54 million and $18 million, respectively.
At December 31, 2019, $18 million of total unrecognized compensation cost related to PBUs not yet vested is
expected to be recognized over the remaining weighted-average period of 1.7 years.

Service-Based Units

The SBUs are classified as liability awards based on the cash settlement feature. 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

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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 granted awards and related dividend equivalents have no shareholder
rights. SBUs that were granted pursuant to the 2017 Omnibus Plan generally vest on the third December 31st following
the grant date, provided the service criterion is satisfied and vested awards will be settled during the subsequent
quarter.

The following table shows the changes in SBUs during the year ended December 31, 2019:

SBUs at December 31, 2018

Granted

Vested and paid out

Forfeited

SBUs at December 31, 2019

Number of
Service
Based Units

488,903

294,539

(2,479)

(35,713)

745,250

The following table presents the classification in the consolidated statements of financial position of obligations

related to outstanding SBUs not yet settled:

(In millions)
Accrued compensation

Other long-term liabilities

Total

December 31,

2019

2018

10 $

20 $

—

The aggregate fair value of SBUs as of December 31, 2019 and 2018 was $30 million and $17 million, respectively.
At December 31, 2019, $10 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

Effective May 4, 2017, Fortis adopted the ESPP, which enables ITC employees to purchase common shares of
Fortis stock. The ESPP allows eligible employees to contribute during any investment period between 1% and 10%
of their annual base pay, with an employee’s aggregate contribution for the calendar year not to exceed 10% of
annual base pay for the year. Employee contributions are made at the beginning of each quarterly investment period
in either a lump sum or by means of a loan from ITC Holdings, which is repayable over 52 weeks from payroll
deductions (or earlier upon certain events) and secured by a pledge on the related purchased shares. ITC Holdings
contributes as additional compensation an amount equal to 10% of an employee’s contribution up to a maximum
annual contribution of 1% of an employee’s annual base pay and an amount equal to 10% of all dividends payable
by Fortis on the Fortis shares allocated to an employee’s ESPP account. All amounts contributed to the ESPP by
employees and ITC Holdings are used to purchase Fortis common shares from Fortis or in the market concurrent
with the quarterly dividend payment dates of March 1, June 1, September 1 and December 1. ITC Holdings
implemented the ESPP during the second quarter of 2017. The cost of ITC Holdings’ contribution for the years ended
December 31, 2019, 2018, and 2017 was less than $1 million, respectively.

17. JOINTLY OWNED UTILITY PLANT/COORDINATED SERVICES

Certain of our Regulated Operating Subsidiaries have agreements with other utilities for the joint ownership of
substation assets and transmission lines. We account for these jointly owned assets by recording property, plant
and equipment for our percentage of 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 are primarily recorded
within operation and maintenance expenses on our consolidated statements of comprehensive income.

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We have investments in jointly owned utility assets as shown in the table below as of December 31, 2019:

(In millions)
ITCTransmission (b)

METC (c)

ITC Midwest (d)

ITC Great Plains (e)

Total

____________________________

Substations

Net Investments (a)
Lines

Other

— $

29 $

69 $

130 $

—

(a) Amount represents our investment in jointly held plant, which has been reduced by the ownership interest

amounts of other parties.

(b) ITCTransmission has joint ownership in two 345 kV transmission lines with a municipal power agency that has
a 50.4% ownership interest in the transmission lines. An Ownership and Operating Agreement with the
municipal power agency provides ITCTransmission with authority for construction of capital improvements and
for the operation and management of the transmission lines. The municipal power agency is responsible for
the capital and operation and maintenance costs allocable to their ownership interest.

(c) METC has joint sharing of several assets within various substations with Consumers Energy, other municipal
distribution systems and other generators. The rights, responsibilities and obligations for these jointly owned
assets are documented in the Amended and Restated Distribution — Transmission Interconnection Agreement
with Consumers Energy and in numerous interconnection facilities agreements with various municipalities and
other generators. In addition, other municipal power agencies and cooperatives have an ownership interest
in several METC 345 kV transmission lines. This ownership entitles these municipal power agencies and
cooperatives to approximately 608 MW of network transmission service from the METC transmission system.
As of December 31, 2019, METC’s ownership percentages for jointly owned substation facilities and lines
ranged from less than 1.0% to 92.0% and 1.0% to 41.9%, respectively.

(d) ITC Midwest has joint sharing of several substations and transmission lines with various parties. ITC Midwest’s
ownership percentages for jointly owned substation facilities and lines ranged from 28.0% to 80.0% and 11.0%
to 80.0%, respectively, as of December 31, 2019.

(e) In 2014, ITC Great Plains entered into a joint ownership agreement with an electric cooperative that has a
49.0% ownership interest in a transmission project. ITC Great Plains will construct and operate the project
and the electric cooperative will be responsible for their ownership percentage of capital and operation and
maintenance costs. As of December 31, 2019, ITC Great Plains’ ownership percentage in the project was
51.0%.

18. RELATED PARTY TRANSACTIONS

Intercompany 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 intercompany receivables from Fortis and such subsidiaries of less than $1 million at December 31, 2019 and
December 31, 2018 and intercompany payables to Fortis and such subsidiaries of less than $1 million at December 31,
2019 and December 31, 2018.

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, 2019 of $10 million and
for each of the years ended December 31, 2018 and 2017 of $8 million. Related party billings for services to Fortis
and other subsidiaries recorded as an offset to general and administrative expenses for ITC Holdings were less than
$1 million for each of the years ended December 31, 2019 and 2018, and $1 million for the year ended December
31, 2017.

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Dividends

We paid dividends of $250 million, $200 million and $300 million during the years ended December 31, 2019,
2018 and 2017, respectively, to ITC Investment Holdings. ITC Holdings also paid dividends of $83 million to ITC
Investment Holdings in January of 2020.

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. We did not make or receive any
tax-related payments during the year ended December 31, 2019. During the year ended December 31, 2019, we
received a payment of $2 million from FortisUS for a tax refund that originated prior to establishing the tax sharing
agreement.

19. 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, establish standards for the management, treatment, storage,
transportation and disposal of solid and hazardous wastes and hazardous materials, and impose obligations to
investigate and remediate contamination in certain circumstances. Liabilities relating to investigation and
remediation of contamination, as well as other liabilities concerning hazardous materials or contamination, such
as claims for personal injury or property damage, may arise at many locations, including formerly owned or operated
properties and sites where wastes have been treated or disposed of, as well as properties 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 results of operations,
financial condition or liquidity.

Our assets and operations also involve the use of materials classified as hazardous, toxic or otherwise
dangerous. Many 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 aboveground 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.
Our facilities and equipment are often situated on or near property owned by others so that, if they are the source
of contamination, others’ property may be affected. For example, aboveground 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 such as wetlands.

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

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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.

Prior to the filing of the MISO ROE Complaints, complaints were filed with the FERC regarding the regional
base ROE rate for ISO New England TOs. In resolving these complaints, the FERC adopted a methodology for
establishing base ROE rates based on a two-step DCF analysis. This methodology provided the precedent for the
FERC ruling on the Initial Complaint and the ALJ initial decision on the Second Complaint for our MISO Regulated
Operating Subsidiaries discussed below.

Initial Complaint

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

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 the two-step DCF methodology adopted in the ISO New England matters. The ROE collected through the MISO
Regulated Operating Subsidiaries’ rates during the period November 12, 2013 through September 27, 2016, a
portion of which was later refunded to customers for the period of the Initial Complaint, consisted of a base ROE
of 12.38% plus applicable incentive adders.

The September 2016 Order required all MISO TOs, including our MISO Regulated Operating Subsidiaries, to
provide refunds of $118 million, including interest, which were completed in 2017 as noted below in “Financial
Statement Impacts”. 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 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.

Related FERC Orders

In April 2017, the D.C. Circuit Court vacated the precedent-setting FERC orders in the ISO New England matters
that established and applied the two-step DCF methodology for the determination of base ROE. The court remanded
the orders to the FERC for further justification of its establishment of the new base ROE for the ISO New England
TOs. On October 16, 2018, in the New England matters, the FERC issued an order on remand which proposed a
new methodology for 1) determining when an existing ROE is no longer just and reasonable; and 2) setting a new
just and reasonable ROE if an existing ROE has been found not to be just and reasonable. The FERC established
a paper hearing on how the proposed new methodology should apply to the ISO New England TOs ROE complaint
proceedings. The FERC issued a similar order, the November 2018 Order, in the MISO ROE Complaints,
establishing a paper hearing on the application of the proposed new methodology to the proceedings pending
before the FERC involving the MISO TOs’ ROE, including our MISO Regulated Operating Subsidiaries.

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November 2019 Order

In January 2020, certain complainants in the MISO ROE dockets filed an appeal of the September 2016 Order
and the November 2019 Order at the D.C. Circuit Court. We believe that the appeal was premature and should
be dismissed, but if not, we will respond in due course.

Financial Statement Impacts

Our MISO Regulated Operating Subsidiaries currently record revenues at the base ROE of 9.88% established
in the November 2019 Order plus applicable incentive adders. See Note 6 for a summary of incentive adders for
transmission rates.

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The recognition of the obligations associated with the MISO ROE Complaints resulted in the following impacts

to the consolidated statements of comprehensive income during each respective period:

(In millions)

Revenue increase (decrease)

Interest expense increase (decrease)

Estimated net income increase (reduction)

Year Ended December 31,
2018

2019

2017

69 $

1 $

(12)

(4)

—

(3)

Development Projects

We are pursuing strategic development projects that may result in payments to developers that are contingent
on the projects reaching certain milestones indicating that the projects are financially viable. We believe it is
reasonably possible that we will be required to make these contingent development payments up to a maximum
amount of $120 million for the period from 2020 through 2023. In the event it becomes probable that we will make
these payments, we would recognize the liability and the corresponding intangible asset or expense as appropriate.

Purchase Obligations

At December 31, 2019, we had purchase obligations of $77 million representing commitments for materials,
services and equipment that had not been received as of December 31, 2019, primarily for construction and
maintenance projects for which we have an executed contract. Of these purchase obligations, $74 million is
expected to be paid in 2020, with the majority of the items related to materials and equipment that have long
production lead times.

Other Commitments

METC

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

Amended and Restated Easement Agreement. Under the Easement Agreement, Consumers Energy provides
METC with an easement to the land on which a majority of METC’s transmission towers, poles, lines and other
transmission facilities used to transmit electricity for Consumers Energy and others are located. 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 expenses.

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 on
behalf of ITC Midwest. 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. Mid-Kansas and ITC Great Plains have entered into the Mid-
Kansas Agreement pursuant to which Mid-Kansas has agreed to perform various field operations and maintenance
services related to certain ITC Great Plains assets.

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Concentration of Credit Risk

Our credit risk is primarily with DTE Electric, Consumers Energy and IP&L, which were responsible for
approximately 21.1%, 23.2% and 24.8%, respectively, or $254 million, $279 million and $298 million, respectively,
of our consolidated billed revenues for the year ended December 31, 2019. These percentages and amounts of
total billed revenues of DTE Electric, Consumers Energy and IP&L include the collection of 2017 revenue accruals
and deferrals and exclude any amounts for the 2019 revenue accruals and deferrals that were included in our
2019 operating revenues but will not be billed to our customers until 2021. 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.

The financial results of ITC Interconnection are currently not material to our consolidated financial statements,

including billed revenues.

20. 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)
Cash and cash equivalents

Restricted cash included in:

Other non-current assets

Total cash, cash equivalents and restricted cash

December 31,

2019

2018

2017

2016

4 $

6 $

66 $

6 $

10 $

68 $

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.

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Supplementary Cash Flow Information

(In millions)
Supplementary cash flows information:

Year Ended December 31,
2018

2017

2019

Interest paid (net of interest capitalized) (a)

228 $

223 $

Income tax refunds received

Supplementary non-cash investing and financing activities:

Additions to property, plant and equipment and other long-lived assets (b)

Allowance for equity funds used during construction

Right-of-use assets obtained in exchange for new operating lease
liabilities (c)

—

213

—

____________________________

(a) Amount for the year ended December 31, 2017 includes $9 million of interest paid associated with the Initial

Complaint. See Note 19 for information on the Initial Complaint.

(b) Amounts consist of current and accrued liabilities for construction, labor, materials and other costs that have
not been included in investing activities. These amounts have not been paid for as of December 31, 2019,
2018 or 2017, respectively, but will be or have been included as a cash outflow from investing activities for
expenditures for property, plant and equipment when paid.

Excess tax benefits are recognized as an adjustment to income tax expense in the consolidated statements of
comprehensive income. Cash retained as a result of those excess tax benefits is presented in the consolidated
statements of cash flows as cash inflows from operating activities.

21. 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 ITCTransmission, METC, ITC Midwest, ITC Great Plains and ITC Interconnection into one
reportable operating segment based on their similar regulatory environment and economic characteristics, among
other factors. They are engaged in the transmission of electricity within the United States, earn revenues from the
same types of customers and are regulated by the FERC.

ITC Holdings and Other

Information below for ITC Holdings and Other consists of a holding company whose activities include debt
financings and general corporate activities and all of ITC Holdings’ other subsidiaries, excluding the Regulated
Operating Subsidiaries, which are focused primarily on business development activities.

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2019
(In millions)
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

2018
(In millions)
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

2017
(In millions)
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
Subsidiaries

ITC Holdings
and Other

Reconciliations/
Eliminations

Total

1,358 $

— $

(31) $

1,327

201

105

710

179

531

8,573

950

9,946

874

119

(150)

(47)

428

—

5,402

—

(531)

—

(5,290)

(9)

203

224

560

132

428

8,582

950

10,058

865

Regulated
Operating
Subsidiaries

ITC Holdings
and Other

Reconciliations/
Eliminations

Total

1,185 $

— $

(29) $

1,156

179

110

585

148

437

7,901

950

9,224

773

114

(144)

(37)

330

—

4,977

—

(437)

—

(4,872)

(4)

180

224

441

111

330

7,910

950

9,329

769

Regulated
Operating
Subsidiaries

ITC Holdings
and Other

Reconciliations/
Eliminations

Total

1,241 $

— $

(30) $

1,211

168

104

664

207

457

7,299

950

8,688

761

120

(149)

(11)

319

—

4,799

—

(457)

—

(4,664)

(6)

169

224

515

196

319

7,309

950

8,823

755

(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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22. SUPPLEMENTARY QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

(In millions)

2019
Operating revenues

Operating income

Net income

2018
Operating revenues

Operating income

Net income

First
Quarter

Second
Quarter

Third
Quarter

Fourth
Quarter

Year

307 $

320 $

321 $

379 (a) $

1,327

166
84

171

174

244 (a)

159 (a)

755

428

279 $

290 $

295 $

154
82

163

292

155

1,156

635

330

____________________________

(a) On November 21, 2019, the FERC issued an order on the MISO ROE Complaints which impacted financial
results for the fourth quarter of 2019. See Note 19 for information regarding the MISO ROE Complaints.

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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, 2019 that have materially affected, or are reasonably likely to materially affect, our internal control
over financial reporting.

ITEM 9B. OTHER INFORMATION.

None.

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.

Pursuant to the Merger Agreement and the Shareholders Agreement, the Board must consist of the Chief
Executive Officer of the Company (Ms. Apsey), a representative of Eiffel, the GIC subsidiary that is a minority
investor in ITC Investment Holdings (Mr. Greenbaum), a minority of representatives of Fortis (Messrs. Perry and
Laurito) and a majority of directors who are independent of Fortis. All directors must be independent of any “market
participant” in MISO and SPP and a majority of the directors must be “independent” as defined in the Shareholders
Agreement. See “Item 13 Certain Relationships And Related Transactions, And Director Independence — Director
Independence.”

Linda H. Apsey, 50. 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

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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.

Robert A. Elliott, 64. 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 is currently the Chairman
of the Board of UNS Energy Corporation, a subsidiary of Fortis, and has been a board member of that company
since 2014. Mr. Elliott currently serves on the board of directors of AAA CSAA Insurance and AAA Auto Club
Partners and is the Chair of the board of directors of AAA Mountain West Group and has been a board member
of that company since 2016. He previously served on the board of directors of 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.

Albert Ernst, 70. Mr. Ernst became a director of the Company in January 2017. Mr. Ernst was also a member
of the ITC Holdings Board of Directors from August 2014 through the closing of the transactions resulting from the
Merger Agreement in October 2016, as described in the Merger Agreement. Mr. Ernst is a retired member of the
law firm of Dykema Gossett PLLC, where he also served as director of Dykema’s Energy Industry Group. His
experience with companies in the public utility, energy, transmission, telecommunications and rural electric
cooperative fields spans more than three decades. With Dykema, Mr. Ernst worked with leading energy clients
including our subsidiaries, ITCTransmission and METC. He also served as a consultant on utility-related matters
to the U.S. Department of Defense, the DOE and the General Services Administration. The Board selected Mr.
Ernst to serve as a director due to his lifelong career in the energy industry, as well as his invaluable experience
with public utility and energy matters and decades of experience in the practice of law.

Alexander I. Greenbaum, 36. Mr. Greenbaum became a director of the Company in July 2019. Mr. Greenbaum
is the Senior Vice President of Infrastructure for GIC. In this role he is responsible for acquisitions and asset
management for a portfolio of power, utility, midstream and transportation assets. Prior to rejoining GIC in May
2015, he was an Executive Director in the Infrastructure group of UBS Investment Bank from July 2005 until May
2015. Mr. Greenbaum currently serves on the board of directors of Arrowhead ST Holdings, a crude oil pipeline
operator, HEP Catalyst InvestCo, a crude oil and natural gas gathering and processing company in the Permian
Basin, and Genesee & Wyoming Railroad. He previously served on the boards of directors of Starwest Generation,
an independent power producer with operations in Arizona, and Texas Transmission Holdings Company. Mr.
Greenbaum was appointed as a member of our Board of Directors by Eiffel.

James P. Laurito, 63. Mr. Laurito became a director of the Company in October 2016. Mr. Laurito has served
as Fortis’ Executive Vice President, Business Development since April 2016. 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 has been Chairman of the Hudson Valley Economic Development
Corporation since January 1, 2015 and currently serves on the board of Fortis’ Central Hudson Gas & Electric
Corporation subsidiary.

Barry V. Perry, 55. Mr. Perry became a director of the Company in October 2016. Mr. Perry is President and
Chief Executive Officer of Fortis and has served as such since January 2015. Prior to his current position at Fortis,
Mr. Perry served as President from June 30, 2014 to December 31, 2014 and prior to that served as Vice President,
Finance and Chief Financial Officer since 2004. Mr. Perry joined the Fortis organization in 2000 as Vice President,
Finance and Chief Financial Officer of Newfoundland Power Inc. Mr. Perry currently serves as a director of the
Fortis utility subsidiaries, FortisBC and UNS Energy Corporation.

Sandra E. Pierce, 61. Ms. Pierce became a director of the Company in 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
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 current chair of the Detroit
Financial Advisory Board and the chair of the Henry Ford Health System. The Board selected Ms. Pierce to serve

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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, 64. 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. The Board has determined that Mr. Prust is an “audit committee financial expert”,
as that term is defined under SEC rules.

A. Douglas Rothwell, 63. Mr. Rothwell became a director of the Company in October 2017. Since 2005 Mr.
Rothwell has served as President and CEO of Business Leaders for Michigan - a business roundtable of the state’s
top 100 CEOs. Mr. Rothwell currently Co-chairs Launch Michigan, the state’s education improvement coalition,
and 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.

Thomas G. Stephens, 71. Mr. Stephens became a director of the Company in January 2017. Mr. Stephens
was also a member of the Board of Directors from November 2012 through the closing of transactions resulting
from the Merger Agreement in October 2016, as described in the Merger Agreement. Mr. Stephens retired in April
2012 from General Motors Company, a designer, manufacturer and marketer of vehicles and automobile parts,
after 43 years with the company. Prior to his retirement, Mr. Stephens served as Vice Chairman and Chief Technology
Officer. Mr. Stephens currently is Vice Chairman of the board of FIRST (For Inspiration and Recognition of Science
and Technology in Michigan Robotics), Chairman of the Board of the Michigan Science Center and sits on the
Board of Managers of Warehouse Technologies LLC and the board of directors of xF Technologies Inc. The Board
selected Mr. Stephens to serve as a director because of his strong technical and engineering background as well
as his experience and proven leadership capabilities assisting a large organization to achieve its business
objectives.

Joseph L. Welch, 71. Mr. Welch has served as Chairman of the Board of Directors of the Company since May
2008 and as a director since 2003. He served as the Company’s President and Chief Executive Officer from 2003
until November 2016 and also served as the Company’s Treasurer from 2003 until 2009. As the founder of
ITCTransmission, Mr. Welch has had overall responsibility for the Company’s vision, foundation and transformation
into the first independently owned and operated electricity transmission company in the United States. Mr. Welch
worked for Detroit Edison Company and other subsidiaries of DTE Energy from 1971 to 2003. During that time,
he held positions of increasing responsibility in the electricity transmission, distribution, rates, load research,
marketing and pricing areas, as well as regulatory affairs that included the development and implementation of
regulatory strategies. Mr. Welch currently serves as a director of Fortis. The Board selected Mr. Welch to serve as
a director because he previously served as the Company’s President and Chief Executive Officer and he possesses
unparalleled expertise in the electric transmission business.

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, 50. Ms. Apsey’s background is described above under “Directors.”

Gretchen L. Holloway, 45. 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

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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. Prior to that, Ms. Holloway served from June 2010 until February 2015 as Director, Special
Projects & Investor Relations of the Company, where she was responsible for supporting the sourcing, evaluation
and execution of mergers and acquisitions and implementing investor relations strategies and objectives. Ms.
Holloway currently serves as a member of the Finance & Audit Committee for the Children’s Hospital of Michigan
Foundation and as a member of the Board of Directors of Inforum.

Jon E. Jipping, 53. Jon E. Jipping has served as Executive Vice President and Chief Operating Officer since
June 2007. Mr. Jipping is responsible for transmission system planning, system operations, engineering, supply
chain, field construction and maintenance, and information technology. Prior to this appointment, Mr. Jipping served
as Senior Vice President - Engineering and was responsible for transmission system design, project engineering
and asset management. 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 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 also serves as the Chair of the Advisory Board of the Michigan
Technological University College of Engineering and as the Chair of the Board of the North American Transmission
Forum.

Daniel J. Oginsky, 46. Mr. Oginsky has served as Executive Vice President and Chief Administrative Officer
since May 2016. In this role, he has responsibility for the Company’s regulatory, federal affairs, marketing and
communications, human resources, strategic planning and enterprise planning process and state government
affairs. Mr. Oginsky served as Executive Vice President, U.S. Regulated Grid Development from February 2015
to May 2016. He was responsible for leading the Company’s growth and expansion through new investments in
regulated electric transmission infrastructure across the United States. Mr. Oginsky joined as our Vice President
and General Counsel in November 2004, served as Senior Vice President and General Counsel since May 2009
and was named Executive Vice President and General Counsel in May 2014. In these roles, Mr. Oginsky was
responsible for the legal affairs of the Company and oversaw the legal department, which included the legal,
corporate secretary, real estate, contract administration and corporate compliance functions. Mr. Oginsky served
as a member of the Advisory Board of Belle Tire, Inc. from 2012 to 2019. Mr. Oginsky currently serves as President
of North Manitou Light Keepers, Inc. and as a member of the Board of Visitors for James Madison College at
Michigan State University.

Christine Mason Soneral, 47. Christine Mason Soneral 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.
As General Counsel, she is responsible for all corporate legal affairs and the leadership of our legal department.
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 matters of the Company’s Regulated Operating Subsidiaries. In 2014, Ms. Mason Soneral was
appointed to the board of Citizens Research Council, a privately funded, not-for-profit public affairs research
organization. Ms. Mason Soneral also currently serves as a member of the Michigan State University College of
Social Science's External Advisory Board and Women’s Leadership Institute.

Krista Tanner, 45. Ms. Tanner has served as our Senior Vice President and Chief Business Unit 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. 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.
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.

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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
officers who were serving as such at December 31, 2019. We refer to these individuals collectively as the “named
executive officers” or “NEOs”.

The Company’s named executive officers for 2019 were:

Name
Linda H. Apsey
Gretchen L. Holloway
Jon E. Jipping
Daniel J. Oginsky
Christine Mason Soneral Senior Vice President and General Counsel

President and Chief Executive Officer
Senior Vice President and Chief Financial Officer
Executive Vice President and Chief Operating Officer
Executive Vice President and Chief Administrative Officer

Position

Executive Summary

The Governance and Human Resources Committee (the “Committee”) is responsible for determining the
compensation of our NEOs and administering the plans in which the NEOs participate. The goals of our compensation
system are to attract first-class executive talent in a competitive environment and to motivate and retain key employees
who are crucial to our success by rewarding Company and individual performance that promotes long-term
sustainable growth and increases 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 2019:

• Base salary increases. Base salary increases were provided to each of our NEOs in 2019 to reward individual

performance and to remain competitive and aligned with market.

• Annual cash incentive bonuses. The NEOs earned cash incentive bonuses for 2019 performance of
approximately 169% of target. This was based on achieving 100% of the performance targets established
under the annual corporate performance bonus plan in early 2019 and achievement of certain performance
factors which resulted in a bonus multiplier of 1.69. 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 March 2019.
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.

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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 incentive awards with improvements in our financial

performance and shareholder value;

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

and

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

Risk and Reward Balance

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

The Committee engaged FW Cook, its independent compensation consultant, to conduct an annual
comprehensive compensation program risk assessment. In July 2019, 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 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, a compensation recoupment policy, 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, the Committee’s independent advisor, compiled
data for the following components of compensation — base salary, target annual cash bonus incentive and target
long-term equity 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. For staff jobs, competitive rates were developed for each of the two distinct market reference
points, as well as an average of the two market reference points. For utility operations jobs, we only used the utility-
specific data due to the industry-specific nature of the roles. 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 has been to target compensation to be in the range between the median and 75th
percentile of the market data, based on consideration of individual characteristics (performance, experience, etc.),
internal equity and other factors. In February 2019, the Committee reviewed the benchmarking study conducted by

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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 50th, 65th 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 is within the targeted range.

Use of Tally Sheets. The Committee reviews tally sheets, every other year, as prepared by management to
facilitate its assessment of the total annual compensation of our NEOs. The tally sheets contain annual cash
compensation (salary and bonuses), long-term equity incentives, benefit contributions and perquisites. In addition,
the tally sheets include retirement program balances, outstanding vested and unvested equity values and potential
severance and termination scenario values.

Pay Review Process. In addition to the Committee’s benchmarking analysis, our CEO reviewed and examined
market survey compensation levels and practices, as well as individual responsibilities and performance, our
compensation philosophy and other related information to develop proposed compensation for each of our NEOs,
other than herself. Ms. Apsey evaluated the performance of the NEOs, other than herself, and made recommendations
on their salaries, target cash bonus incentive levels and long-term equity incentive awards. The Committee considered
these recommendations in its decision making and conferred with Pay Governance, its compensation consultant at
the time, to understand the impact and result of any such recommendations. The Committee uses market data and
recommendations from the Committee’s consultant 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 2019 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. 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.

In aggregate, the NEOs’ target total direct compensation value (salary, annual target bonus and long-term incentive
opportunities) was generally within the targeted range when compared to the blended average of the utility and
general industry surveys. Base salaries are generally at the lower end of the targeted market range with target
incentive opportunities set higher within the market range, which combine to provide competitive target total direct
compensation around the target range of the market 50th and the 75th percentile. The Committee continues to
monitor and balance competitive practice, talent needs and cost considerations when setting compensation.

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.

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The 2019 base salaries for the NEOs, including any year-over-year change, were:

NEO

Linda H. Apsey

Gretchen L. Holloway

Jon E. Jipping

Daniel J. Oginsky

Christine Mason Soneral

2018 Base Salary
$

755,000 $
370,000

2019 Base Salary
800,000

Percent Increase

6.0%

5.4%

4.5%

3.6%

3.2%

390,000

580,000

485,000

390,000

555,000

468,000

378,000

Annual Corporate Performance Bonus

Early each year, the Committee approves our annual corporate performance bonus plan 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. Target levels for the corporate performance goals were determined
based on long-term strategic plans, historical performance, expectations for future growth and desired improvement
over time.

The annual corporate performance bonus plan 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. The plan would not pay for achieving below-target performance on any goal but would pay for
achievement of target performance on those goals that were achieved even though other goals were not achieved.
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 established to motivate NEOs toward operational excellence and superior financial performance and were
designed to be challenging to meet, while remaining achievable.

For 2019, financial measures, representing 20%, plus the capital project plan, representing 30%, determined
50% of the target bonus opportunity, while operational performance measures, including Safety & Compliance,
representing 20% and System Performance, representing 30%, determined the remaining 50% of the target bonus
opportunity. This reflected the inherent importance of driving operational performance, reliability and needed
investment in our transmission system for the benefit of our customers.

The annual corporate performance bonus plan consisted of three primary measurement categories: Financial,
Safety & Compliance, and System Performance. 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 infrastructure protection
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 2019, 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.

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Financial goals represented 20% of the total maximum annual bonus target and included specific measures for

Non-Field Operation and Maintenance Expense and Net Income.

Category

Goal

Outage
frequency

Rationale for
Goal
Reducing and
limiting
system
outages are
critical to
ensuring
system
reliability.

System
Performance
and Capital
Project Plan

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

2019 Results
15% ITCTransmis
sion - 10

Actual
Payout

15%

METC - 17

ITC Midwest
- 56/48

15% All high
priority
initiatives
completed
under budget

15%

15 - 30% $820M

30%

Rationale for Target

Target unchanged from prior
year for ITCTransmission and
METC, reduced from prior year
for ITC Midwest; all targets
aligned with industry benchmark
data. Number of Forced,
Sustained Line Outages,
excluding the "External" cause
classification, for:

ITCTransmission (13 or fewer,
representing top decile
performance);

METC (25 or fewer, representing
top decile performance);

ITC Midwest (66 or fewer,
representing a reduction of 2
outages and top decile
performance, no more than 55
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 2019
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 $91.3M.

Target is based on accrued
capital investment.

The maximum payout
represents the risk-adjusted
capital investment plan for 2019,
with a threshold level also
established.

Complete $666M of the 2019
Capital Expenditure budget to
achieve 30%; Complete $631M
to achieve 15%.

Total Bonus (as a percent of target bonus level)

____________________________

60%

100%

60%

100%

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(1) We utilize adjusted net income as a criterion in measuring achievement of financial goals for our annual
corporate performance bonus. This non-GAAP financial measure reconciles to net income of our Regulated
Operating Subsidiaries as follows:

(in millions)
Net Income of Regulated Operating Subsidiaries
Adjustments Related to ROE Matters
Other Adjustments

Adjusted Net Income

2019

531
(49)
2
484

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

Measure
Capital Investment Plan
Cash from Operations Pre-Working
Capital
Adjusted Consolidated Net Income (2)

Development Goals
Bonus Multiplier

____________________________

Threshold
$701M

Achievement
(1)
$820M

Multiplier
2.00x

Weight
25%

Result
0.50x

$627M
$367M

$654M
$379M

1 Goal

Not Met

1.75x
2.00x

1.00x

25%
25%

25%

0.44x
0.50x

0.25x
1.69x

(1) Amounts presented are rounded to the nearest million.

(2) 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)
Net Income
Adjustments Related to ROE Matters
Adjusted Consolidated Net Income

2019

428
(49)
379

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%. Achievement
against performance scales related to each of the above metrics produced an executive bonus multiplier of 1.69x.
This performance factor was applied to each executive’s ACPB to produce a final payment of approximately 169%
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 2019 were 100% of base salary for each NEO.

Long-Term Incentive

The Committee provides and maintains a long-term equity incentive program under the 2017 Omnibus Plan. In
February 2019, the Committee approved grants of SBUs and PBUs to employees, including 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 can be earned for results in two equally-weighted measures,
Total Shareholder Return (relative to Fortis’ peer group) and cumulative consolidated net income, over the three-
year performance period. The PBU metrics were selected as Total Shareholder Return aligns with the Fortis
shareholder experience and cumulative consolidated net income measures the sustained growth (organic and
development), cost management and efficiency. Each unit is generally equivalent to one share of Fortis stock (as
traded on the Toronto Stock Exchange) and earned units are payable in cash. 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

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and more detailed terms of the 2019 SBU and PBU grants made under the 2017 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 shareholder. Total value for the award for each grantee was determined based on a percentage
of salary. For the NEOs, when the 2019 awards were made, the award values were targeted to be:

NEO

Ms. Apsey
Ms. Holloway
Mr. Jipping
Mr. Oginsky
Ms. Mason Soneral

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.

On February 4, 2020, the Board approved the Executive Omnibus Plan. The Executive Omnibus Plan is a long-
term equity incentive program that is available for employees with a title of Vice President or higher. The Committee
has approved PBU grants, and may in the future approve grants of SBUs, PBUs, dividend equivalent units or cash
incentive awards under the Executive Omnibus Plan.

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 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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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 5
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. Each of the NEOs is in compliance with this policy.

Recoupment Policy

Our Recoupment Policy provides that in the event of any restatement of financial results, our NEOs will be required

to reimburse the Company for an amount equal to the sum of:

• Any bonus or other incentive-based or equity-based compensation received, earned or recognized by the
NEO during the 12-month period following the first public issuance or filing with the SEC of the financial
document embodying such financial reporting requirement in excess of the amount that would have been
received, earned or recognized if the restated financial results had been released instead; and

• Any profits realized by the NEO from the sale of securities of the Company during that 12-month period.

The Board of Directors or the Committee will determine, in its reasonable discretion, based on the circumstances,
the amount, form and timing of recovery. The Recoupment Policy applies to any equity-based grants and incentive
cash compensation awards.

Jipping Letter Agreement

In February 2019, Mr. Jipping entered into a letter agreement with the Company amending his employment
agreement and long-term incentive awards, including his SBU and PBU awards granted under the 2017 Omnibus
Plan. Under the terms of the letter agreement upon Mr. Jipping’s voluntary termination of employment, his SBU and
PBU awards, which would otherwise be forfeited, will continue to vest on their normal schedule even if Mr. Jipping
does not meet the retirement age, as defined in the 2017 Omnibus Plan, for continued vesting at the time of his
termination. The letter agreement also removes Section 7c(ii)(B) of Mr. Jipping’s employment agreement which
defines his rights to terminate the employment agreement if his job responsibilities and authority were substantially
diminished.

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Governance and Human Resources Committee Report

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

ALEXANDER I. GREENBAUM
A. DOUGLAS ROTHWELL

BARRY V. PERRY
THOMAS G. STEPHENS

SANDRA E. PIERCE

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 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
($) (2)

Non-Equity
Incentive Plan
Compensation
($) (3)

Change in
Pension Value
& Non-
qualified
Deferred
Compensation
Earnings
($)(4)

All Other
Compensation
($) (5)

(e)

(f)

(g)

(h)

Total ($)

(i)

Salary ($)

(c)

Bonus
($) (1)

(d)

794,692

— $

2,061,860

1,352,000

322,636

55,516

$ 4,586,704

752,712

725,000

388,115

367,962

317,981

578,000

553,674

529,289

483,988

466,685

445,327

389,469

377,204

362,404

—

644,700

—

265,000

—

538,100

—

444,150

—

529,899

1,747,386

1,760,834

703,598

599,433

552,539

1,046,405

899,149

909,553

875,001

758,200

765,053

703,598

612,373

620,551

1,169,118

1,205,313

659,100

572,945

581,875

980,200

859,418

889,438

819,650

724,698

748,125

659,100

585,333

606,813

123,927

232,747

147,032

81,152

80,454

568,493

63,980

345,722

236,208

51,865

177,356

170,742

66,424

146,625

66,909

57,751

36,362

34,351

33,126

38,169

37,869

37,694

36,742

36,556

35,972

36,500

35,250

36,378

3,860,052

4,626,345

1,934,207

1,655,843

1,830,975

3,211,267

2,414,090

3,249,796

2,451,589

2,038,004

2,615,983

1,959,409

1,676,584

2,302,670

Name

(a)

Linda H. Apsey,
President & CEO

Gretchen L. Holloway
SVP & CFO

Jon E. Jipping,
EVP & COO

Daniel J. Oginsky,
EVP & CAO

Christine Mason Soneral,
SVP & General Counsel

Year

(b)

2019

2018

2017

2019

2018

2017

2019

2018

2017

2019

2018

2017

2019

2018

2017

____________________________

(1) The compensation amounts reported in this column include retention bonuses and bonuses paid in connection
with expanding responsibilities. Bonuses paid in connection with our annual corporate performance bonus plan
are reported in the “Non-Equity Incentive Plan Compensation” column of the Summary Compensation Table. In
2017, Ms. Mason Soneral earned $162,399 in accordance with the retention payments related to her employment
agreement amendment. In 2017, Ms. Holloway received a lump sum payment of $125,000 and Mr. Jipping
received a lump sum payment of $11,000 due to their expanding responsibilities. These bonuses are set forth
in the following table:

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Name

Year

Retention
Bonus ($)

Other
Bonuses ($)

Total Bonus
($)

Linda H.
Apsey

Gretchen
L.
Holloway

Jon E.
Jipping

Daniel J.
Oginsky

Christine
Mason
Soneral

2019

2018

2017

2019

2018

2017

2019

2018

2017

2019

2018

2017

2019

2018

2017

— $

—

644,700

—

— $

—

644,700

—

140,000

125,000

265,000

—

527,100

11,000

538,100

—

444,150

—

529,899

—

444,150

—

529,899

(2) The amounts reported in this column represent the fair value of PBU awards and SBU awards granted to the
NEOs under the 2017 Omnibus 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 expected
payout of the performance and market conditions, with the market condition fair value determined using a Monte
Carlo simulation valuation model. 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.”

(3) The amounts reported in this column include cash awards tied to the achievement of annual Company
performance goals under our annual corporate performance bonus plan in effect for each of 2019, 2018 and
2017. For information regarding the corporate goals for 2019, see “Compensation Discussion and Analysis -
Key Components of Our NEO Compensation Program - Annual Corporate Performance Bonus."

(4) All amounts reported in this column pertain to the tax-qualified defined benefit pension plan and the supplemental
nonqualified, noncontributory retirement plan maintained by the Company. None of the income on nonqualified
deferred compensation was above-market or preferential. Variations in the amounts from year to year reflect an
additional year of service and pay changes used in the accrued benefit, as well as changes in assumptions on
which the benefits are calculated, for which the formula has not been materially revised. The discount rate used
for the present value of accumulated benefits was 3.67% in 2017, 4.39% in 2018 and 3.44% in 2019. The long-
term interest crediting rate for the cash balance component of the Retirement Plan and ESRP changed from
4.50% to 4.00% at year-end 2019.

(5) 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 2019, 2018 and 2017
are itemized in the table below as required by applicable SEC rules.

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Name

Linda H.
Apsey

Gretchen L.
Holloway

Jon E.
Jipping

Daniel J.
Oginsky

Christine
Mason
Soneral

Year

2019

2018

2017

2019

2018

2017

2019

2018

2017

2019

2018

2017

2019

2018

2017

Personal
Use of
Company
Aircraft

401(k)
Match

Other
Benefits

Total

$ 16,800

$ 19,777

18,939

55,516

14,750

14,400

15,100

14,750

14,400

16,800

16,500

16,200

15,100

14,750

14,400

15,100

14,750

14,400

25,074

12,752

—

27,085

30,599

21,262

19,601

18,726

21,369

21,494

21,642

21,806

21,572

21,400

20,500

21,978

66,909

57,751

36,362

34,351

33,126

38,169

37,869

37,694

36,742

36,556

35,972

36,500

35,250

36,378

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 2019.

Estimated Future Payouts Under
Non-Equity Incentive Plan Awards

Estimated Future Payouts Under
Equity Incentive Plan Awards

Award
Type

Threshold
($)

Target ($)
(1)

Maximum
($)(1)

Threshold
(#)

Target (#)
(2)

Maximum
(#)(2)

All Other
Stock
Awards:
Number
of Shares
of Stock
or Units
(#)

Grant
Date Fair
Value of
Stock and
Option
Awards
($)(3)

(c)

(d)

(e)

(f)

(g)

(h)

(i)

(j)

Name

(a)

Grant
Date

(b)

3/6/2019

SBU

— $

—

20,141

$ 666,667

20,141

40,282

80,564

— 1,333,334

—

Linda H. Apsey

3/6/2019

PBU

ACPB

3/6/2019

SBU

Gretchen L. Holloway

3/6/2019

PBU

Jon E. Jipping

ACPB

3/6/2019

SBU

3/6/2019

PBU

ACPB

3/6/2019

SBU

Daniel J. Oginsky

3/6/2019

PBU

Christine Mason
Soneral

ACPB

3/6/2019

SBU

3/6/2019

PBU

ACPB

____________________________

—

800,000

1,600,000

—

390,000

780,000

—

580,000

1,160,000

—

485,000

970,000

—

6,873

227,496

6,873

13,746

27,492

—

10,222

20,443

40,886

—

8,548

17,095

34,190

—

6,874

13,746

27,496

—

454,993

—

10,222

338,348

—

676,663

—

8,547

282,906

—

565,845

—

6,873

227,496

—

454,993

—

390,000

780,000

—

(1) The amount shown in Column (d) represents the potential payout for the ACPB based on “target bonus levels.”
The amount payable assuming maximum achievement of all bonus goals 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 2019 Fortis peer group and (2) cumulative consolidated net income for each fiscal year 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 2017 Omnibus Plan with a grant date of
March 6, 2019. The PBUs reflected here are recorded at fair value at the date of grant, which was $33.10 per
share. The SBUs reflected here are recorded at fair value at the date of grant, which was $33.10 per share.
Share fair values were converted from Canadian Dollars to US Dollars using the “Award Conversion Rate”
defined in the 2017 Omnibus Plan.

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.

The Committee had the power to award SBUs and PBUs in the form of equity or cash under the 2017 Omnibus
Plan with the terms of each award set forth in a written agreement with the recipient. Grants made in 2019 to the
NEOs were made under the 2017 Omnibus Plan pursuant to terms stated in the SBU and PBU award agreements.

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Performance-Based Unit Award Agreements

The PBU award agreements entered into with each NEO on March 6, 2019 (the “PBU Grant Date”) (each a “PBU
Agreement”) provide generally that the award will vest on December 31, 2021 (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. One-half of the Target Number of PBUs shall be related to the Fortis Total Shareholder Return
goal (the “TSR goal”) and one-half of the Target Number of PBUs shall be related to the Cumulative Consolidated
Net Income goal (the “CCNI goal”). The PBUs will become earned as set forth in the following table:

Measurement Category

Goal at
Threshold

Shares at
Threshold

Goal at
Target

Shares at
Target

Goal at
Maximum

Shares at
Maximum

Fortis Total Shareholder
Return

30th
percentile

Cumulative Consolidated
Net Income

99% of
Target

50% of TSR
Target Units
50% of
CCNI Target
Units

50th
percentile

100% of
Target

100% of
TSR Target
Units
100% of
CCNI Target
Units

85th
percentile

102% of
Target

200% of
TSR Target
Units
200% of
CCNI Target
Units

The performance period for the award is January 1, 2019 through December 31, 2021 (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 2019 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.

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 2017 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

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 in
the Committee’s discretion. Cumulative Consolidated Net Income for the Company during the Payment Criteria
Period shall be the sum of the Consolidated Net Income for each of the three years in the Payment Criteria Period.

If the grantee ceases to be employed before the PBU Vesting Date due to death or disability, 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 “Retirement” or “Involuntary Termination Without Cause”, (i) one-third of the

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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 one 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, Retirement or Involuntary
Termination Without Cause, grantee will forfeit the award. Under the terms of the Jipping Letter Agreement, upon
Mr. Jipping’s voluntary termination of employment, his PBU awards, which would otherwise be forfeited, will continue
to vest on their normal schedule even if Mr. Jipping does not meet the retirement age, as defined in the 2017 Omnibus
Plan, for continued vesting at the time of his termination.

“Involuntary Termination Without Cause” means a termination of the grantee’s employment by the Company other
than due to the grantee’s death, disability, Retirement, voluntary resignation or for “Cause” (as defined in the PBU
Agreement). “Retirement” is defined to mean termination of grantee’s employment with the Company upon or after
attaining “normal retirement age” (as defined in the International Transmission Company Retirement Plan).

Upon a “Change of Control”, as defined in the 2017 Omnibus Plan, all outstanding PBUs become redeemable
on the trading day that is immediately prior to the effective date of the consummation of the event resulting in the
Change of Control (the “Change of Control Redemption Date”). In the event of a Change of Control, 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.

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 March 6, 2019 (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) December 31, 2021 (the “SBU Vesting Date”) or (ii) the grantee's death or disability. If the
grantee ceases to be employed before the SBU Vesting Date due to “Retirement” or “Involuntary Termination Without
Cause” (i) one-third of the number of SBUs to which the grantee would have otherwise been entitled shall vest if
termination occurred one or after the one-year anniversary of the SBU Grant Date and before the two-year anniversary
of the SBU Grant Date, and (ii) two-thirds of the number of SBUs to which the grantee would have otherwise been
entitled shall vest if termination occurred on or after the two-year anniversary of the SBU Grant Date but before the
SBU Vesting Date. If termination occurs prior to the SBU Vesting Date other than as a result of death, disability,
Retirement or Involuntary Termination Without Cause, grantee will forfeit the award. Under the terms of the Jipping
Letter Agreement upon Mr. Jipping’s voluntary termination of employment, his SBU awards, which would otherwise
be forfeited, will continue to vest on their normal schedule even if Mr. Jipping does not meet the retirement age, as
defined in the 2017 Omnibus Plan, for continued vesting at the time of his termination.

Upon a Change of Control, all unvested SBUs are deemed to be fully vested and redeemable on the Change of
Control Redemption Date. “Retirement”, “Involuntary Termination Without Cause” and “Change of Control” are defined
in the same manner as defined in the description of the PBU Agreement disclosed above. Grantees are entitled to
receive additional dividend equivalent SBUs in the same manner as defined in the description of the PBU Agreement
disclosed above.

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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

2019 held by the NEOs.

Name

(a)

Linda H. Apsey

Gretchen L. Holloway

Jon E. Jipping

Daniel J. Oginsky

Number of Shares or
Units of Stock That
Have Not Vested (#)
(SBUs)

Market Value of
Shares or Units of
Stock That Have Not
Vested ($) (SBUs) (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)

18,358 (2) $

20,673 (4)

6,298 (2)

7,055 (4)

9,446 (2)

10,492 (4)

7,966 (2)

8,773 (4)

6,434 (2)

7,055 (4)

762,220

858,351

261,491

292,907

392,215

435,632

330,732

364,249

267,120

292,907

36,716 (3)

41,346 (5)

12,595 (3)

14,109 (5)

18,893 (3)

20,983 (5)

15,931 (3)

17,547 (5)

12,867 (3)

14,109 (5)

1,524,448

1,716,686

522,944

585,806

784,437

871,214

661,455

728,551

534,238

585,806

Christine Mason Soneral

____________________________

(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 31, 2019 ($41.52).

(2) These unvested SBUs were granted in 2018 and generally vest on December 31, 2020. These SBU numbers

include the original SBU grant plus dividend equivalent units earned.

(3) These unvested PBUs were granted in 2018 and generally vest on December 31, 2020. 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 target performance goals have been achieved.

(4) These unvested SBUs were granted in 2019 and generally vest on December 31, 2021. These SBU numbers

include the original SBU grant plus dividend equivalent units earned.

(5) These unvested PBUs were granted in 2019 and generally vest on December 31, 2021. 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 target performance goals have been achieved.

Equity grants made to NEOs in 2018 and 2019 were made pursuant to the 2017 Omnibus Plan. The terms of the

grants are described above in the narrative discussion accompanying the “Grants of Plan-Based Awards” Table.

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Option Exercises and Stock Vested

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

2019:

Name

(a)

Linda H. Apsey

Gretchen L. Holloway

Jon E. Jipping

Daniel J. Oginsky

Christine Mason Soneral

Stock Awards

Number of Shares or
Units of Stock Acquired
on Vesting (#)

Value of Shares or Units
of Stock Realized on
Vesting ($) (1)

(b)

(c)

21,699 (2) $

53,807 (3) $

6,808 (2) $

16,885 (3) $

11,207 (2) $

27,794 (3) $

9,427 (3) $

23,378 (2) $

7,646 (2) $

18,962 (3) $

875,052

2,170,185

274,575

681,005

451,999

1,121,012

380,217

764,807

308,389

764,807

____________________________

(1) Value is based on the 5-day VWAP price of common stock on the TSX on the vesting date, converted from
Canadian Dollars to US Dollars using the “Award Conversion Rate” defined in the 2017 Omnibus Plan, which
is $40.3327

(2) Amounts reported reflect the vesting of SBUs granted March 8, 2017 and associated dividend equivalent units.

(3) Amounts reported reflect the vesting of PBUs granted March 8, 2017 and associated dividend equivalent units.
The award contains performance conditions established by the Committee. The performance period ended on
December 31, 2019. The Committee certified the achievement of 124% of the applicable performance goals on
February 4, 2020.

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Pension Benefits

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

Pension Benefits Table

Name

(a)

Plan Name

(b)

Cash Balance Component

Linda H. Apsey

ESRP Shift

Total Qualified Plan

ESRP

Cash Balance Component

Gretchen Holloway

Total Qualified Plan

ESRP

Traditional Component

Jon E. Jipping

Total Qualified Plan

ESRP

Cash Balance Component

Daniel J. Oginsky

Total Qualified Plan

Christine Mason
Soneral

ESRP

Cash Balance Component

Total Qualified Plan

ESRP

____________________________

Number of Years
Credited Service (#)
(1)

Present Value of
Accumulated
Benefit ($)(2)

Payments During
Last Fiscal Year
($)

(c)

(d)

(e)

25.58

N/A

16.83

15.95

4.91

29.03

14.92

15.20

12.29

12.28

421,996

37,221

459,217

1,820,188

279,327

285,187

1,741,308

1,505,330

343,226

1,200,313

275,932

668,476

N/A

(1) Credited service is estimated as of December 31, 2019 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. 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, 2019 (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, 2019. The rate at which future expected
benefit payments were discounted in calculating present values was 3.44%, the same rate used for fiscal
year-end 2019 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 2.16% for 2020 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

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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 Adjusted RP-2014 table projected for
future mortality improvements with MP-2017 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.

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 $280,000 in 2019 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 $225,000
payable as a single life annuity beginning at normal retirement age in 2019).

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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 monthly as an annuity for his lifetime, beginning at age 60, is

approximately $118,000. He is fully vested.

Cash Balance Component of Qualified Plan

Mses. Apsey, Holloway and Mason Soneral and Mr. Oginsky 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 applies under the traditional
component of the Qualified Plan ($280,000 in 2019). Each year, a NEO’s account is also increased by an “interest
credit” based on 30-year Treasury rates.

Upon termination of employment, a vested NEO may elect full payment of his or her account. Alternate forms of

benefit (e.g., various forms of annuities) are available as well that have the same actuarial value as the account.

Mses. Apsey, Holloway and Mason Soneral and Mr. Oginsky 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 2019 is approximately $411,000, Ms. Holloway’s is approximately $265,000, Ms. Mason Soneral’s is
approximately $265,000, and Mr. Oginsky’s is approximately $328,000.

ESRP Shift Benefit in Qualified Plan

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
annual bonus 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.

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Ms. Apsey has received ESRP shift additions to her Qualified Plan cash balance account. There was no shift of
compensation credits for 2019, although previous shifts have continued to earn interest credits. As of year-end 2019,
her ESRP shift balance was approximately $36,000.

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 annual corporate performance bonus 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, 2019, the ESRP account values, net of the amounts shifted
to the Qualified Plan, are as follows:

Ms. Apsey

Ms. Holloway

Mr. Jipping

Mr. Oginsky

Ms. Mason Soneral

1,773,953

270,720

1,498,051

1,148,252

640,935

The ESRP is funded with a Rabbi Trust, which we cannot use for any purpose other than to satisfy the benefit
obligations under the ESRP, except in the event of the Company’s bankruptcy, in which case the assets are available
to general creditors.

Nonqualified Deferred Compensation

We maintain the Executive Deferred Compensation Plan under which nonqualified deferred compensation is
permissible. 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 2018 and his deferral was
withheld in 2019. Mr. Jipping also elected to participate in 2019, and his deferral will be made in 2020 due to his
2019 bonus payment occurring in 2020. Mr. Jipping is the only NEO that participated in the Executive Deferred
Compensation Plan in 2019.

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 Messrs. Jipping and Oginsky
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. 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

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describes the material terms of the employment agreements, as amended, with the NEOs who remained employed
by the Company on December 31, 2019.

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 substantially to perform his or her duties (other than as a result of
total or partial incapacity due to physical or mental illness) for a period of 10 days following written notice
by the Company to the NEO of such failure; dishonesty in the performance of the NEO’s duties; a NEO’s
conviction of, or plea of nolo contender to, a crime constituting a felony or misdemeanor involving moral
turpitude; willful malfeasance or willful misconduct in connection with a NEO’s duties; any act or omission
which is injurious to the financial condition or business reputation of the Company; or violation of the non-
compete or confidentiality provisions of the employment agreement.

• Good reason means: a greater than 10% reduction in the total value of the NEO’s base salary, target bonus,

and employee benefits; or if the NEO’s responsibilities and authority are substantially diminished.

If a NEO’s employment is terminated with cause by the Company or by the NEO without good reason, the NEO
will generally only receive his or her accrued but unpaid compensation and benefits as of the date of his or her
employment termination. If the NEO terminates due to death or disability (as defined in the employment agreements),
the NEO (or the NEO’s spouse or estate) would also receive a pro rata portion of his or her current year annual
target bonus.

If a NEO’s employment is terminated by the Company without cause or by the NEO for good reason, the NEO
will receive the following, subject to the NEO’s execution of a release agreement and commencing generally on the
earliest date that is permitted under Section 409A of the Internal Revenue Code:

•

any accrued but unpaid compensation and benefits including:

Ms. Apsey: cash balance and ESRP shift under the Qualified Plan and vested portion of ESRP

balance;

Mr. Jipping: annual benefit under the traditional component of the Qualified Plan and vested portion

of ESRP balance; and

Mr. Oginsky, Ms. Mason Soneral and Ms. Holloway: 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 annual corporate performance bonus 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;

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•

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 for Messrs. Jipping and Oginsky, participation in our Postretirement
Welfare Plan only if, by the end of their specified severance period, they have achieved the necessary age
and service credit otherwise necessary to meet the eligibility requirements. In addition, if we terminate our
Postretirement Welfare Plan and, by application of the provisions described in the prior sentence, any of
these NEOs would otherwise be entitled to retiree welfare benefits, we will establish other coverage for the
NEO or the NEO will receive a cash payment equal to our cost of providing such benefits, in order to assist
the NEO in obtaining other retiree welfare benefits.

In addition, while employed by us and for a period of two years after any termination of employment without cause
by the Company (other than due to their disability) or for good reason by them and for a period of one year following
any other termination of their employment, the NEOs will be subject to certain covenants not to compete with or
assist other entities in competing with our business and not to encourage our employees to terminate their employment
with us. At all times while employed and thereafter, all of the NEOs will also be subject to a covenant not to disclose
confidential information.

In the event the NEO becomes subject to excise taxes under Section 4999 of the Internal Revenue Code as a
result of payments and benefits received under the employment agreements or any other plan, arrangement or
agreement with us, we will pay the NEO only that portion of such payments which are in total equal to one dollar
less than the amount that would subject the NEO to the excise tax.

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, 2019.

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)

— $

1,600,000

4,012,555

— $

—

800,000

1,352,000

—

254,075

1,620,567

508,149

1,585,573

3,241,151

—

25,000

29,255

—

25,000

29,255

693,833

—

— $

4,462,312

9,318,783

5,661,718

Compensation

Cash Severance

Target Short-term Bonus

Pro Rata Short-term

(Annual) Incentive Comp

Retention Awards

Service-Based Unit

Awards (7)

Performance-Based Unit

Awards

Benefits and Perquisites

Retirement Plan

ESRP

Perquisites

Health & Welfare Benefits

Postretirement Welfare

Plan (5)

Total Payout:

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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)

— $

780,000

1,662,104

— $

—

390,000

659,100

—

87,164

554,417

174,315

—

25,000

29,462

542,889

(981,273)

—

25,000

29,462

1,108,760

—

Compensation

Cash Severance

Target Short-term Bonus

Pro Rata Short-term

(Annual) Incentive Comp

Service-Based Unit

Awards (7)

Performance-Based Unit

Awards (8)

280G Cutback

Benefits and Perquisites

Retirement Plan

ESRP

Perquisites

Health & Welfare Benefits

Total Payout:

— $

1,755,041

2,491,699

2,053,177

Jon E. Jipping - Termination Scenarios: Value of Potential Payments

Total Value of Severance, Benefits and Unvested Equity Awards(1)(2)

Voluntary
Resignation or
Voluntary Good
Reason

Involuntary For
Cause

Involuntary Not-
for-Cause

Change In
Control (pre-tax)
(3)

Disability

Death (pre-
retirement)(4)

— $

1,160,000

2,980,981

— $

—

827,826

—

580,000

980,200

—

130,733

827,826

261,479

811,854

1,655,659

—

25,000

29,176

—

25,000

29,176

723,287

—

827,826

— $

3,309,875

6,378,324

3,063,485

Compensation

Cash Severance

Target Short-term Bonus

Pro Rata Short-term

(Annual) Incentive Comp

Service-Based Unit

Awards (7)

Performance-Based Unit

Awards (8)

Benefits and Perquisites

Retirement Plan (6)

ESRP

Perquisites

Health & Welfare Benefits

Postretirement Welfare

Plan (5)

Total Payout:

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Daniel J. Oginsky - Termination Scenarios: Value of Potential Payments

Total Value of Severance, Benefits and Unvested Equity Awards(1)(2)

Compensation

Cash Severance

Target Short-term Bonus

Pro Rata Short-term

(Annual) Incentive Comp

Service-Based Unit

Awards (7)

Performance-Based Unit

Awards (8)

Benefits and Perquisites

Retirement Plan

ESRP

Perquisites

Health & Welfare Benefits

Voluntary
Resignation

Involuntary For
Cause

Involuntary Not-
for-Cause or
Voluntary Good
Reason

Change In
Control (pre-tax)
(3)

Disability

Death (pre-
retirement)(4)

— $

970,000

2,503,869

— $

—

485,000

819,650

—

110,249

695,003

220,485

682,547

1,389,995

—

25,000

30,401

—

25,000

30,401

—

Total Payout:

— $

2,175,785

4,756,470

2,569,998

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)

— $

780,000

2,038,491

— $

—

390,000

659,100

—

89,047

560,063

178,079

550,407

1,120,053

—

25,000

30,665

—

25,000

30,665

—

Compensation

Cash Severance

Target Short-term Bonus

Pro Rata Short-term

(Annual) Incentive Comp

Service-Based Unit

Awards (7)

Performance-Based Unit

Awards (8)

Benefits and Perquisites

Retirement Plan

ESRP

Perquisites

Health & Welfare Benefits

Total Payout:

— $

1,761,891

3,863,726

2,070,116

____________________________

(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
(5), and additional pension benefits upon death, 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. Holloway would be subject to an excise tax on the employer
payments as of the assumed change in control date; therefore, a cutback in the amount of $981,273 has
been reflected.

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(4) In the event of Mr. Jipping’s termination for death (pre-retirement), his spouse would receive half the 50%
joint and survivor annuity under the traditional component of the Qualified Plan, also reduced to reflect a
90% early retirement factor that would apply at age 58 since Mr. Jipping does not have 30 years of service
as of December 31, 2019. Under termination for death (pre-retirement), Ms. Apsey’s, Ms. Mason Soneral’s,
Ms. Holloway’s, and Mr. Oginsky’s Qualified Plan benefits are payable immediately to the surviving spouse
(if any) and ESRP benefits are payable to a designated beneficiary. The above termination scenarios do not
reflect the reduction in present value of death benefits ($57,899 for Ms. Apsey, $28,636 for Ms. Holloway,
$970,244 for Mr. Jipping, $66,948 for Mr. Oginsky, and $38,909 for Ms. Mason Soneral) compared to present
value in the Pension Benefits Table.

(5) The value of the Postretirement Welfare Plan benefit is included in involuntary termination not for cause and
change in control scenarios for Ms. Apsey and Mr. Jipping since their employment agreement includes a
provision for deemed satisfaction of the eligibility requirements when terminated under these scenarios. 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 3.61%, the same rate used for fiscal year-end 2019 accounting disclosure of the Postretirement Welfare
Plan.

(6) The Pension Benefits Table assumes that Mr. Jipping would not be terminated before retirement age and
no early retirement reduction was applied. In all termination scenarios, however, a 90% early retirement
factor would apply at age 58 because Mr. Jipping has less than 30 years of service as of December 31,
2019. The above table does not reflect the reduction in the present value ($174,131 except for death) due
to applying the 90% early retirement factor.

(7) Under the 2017 Omnibus Plan, outstanding and unvested SBUs and respective dividend equivalents shall
be deemed to be vested SBUs and redeemable on the Change of Control Redemption Date (as defined in
the 2017 Omnibus Plan). In the case of Death or Disability (each as defined in the 2017 Omnibus Plan)
termination, outstanding and unvested SBUs and respective dividend equivalents shall be deemed to be
vested SBUs and redeemable on the date of the death or on the date on which the grantee’s service is
terminated due to Disability. In the case of Retirement or Involuntary Termination Without Cause (each as
defined in the 2017 Omnibus Plan) within one year of the grant date, outstanding and unvested SBUs and
respective dividend equivalents shall be deemed to be forfeited. If Retirement or Involuntary Termination
Without Cause occurs one year or more after the grant date, SBUs and respective dividend equivalents
shall be deemed to have vested pro-rata based on the period served from the grant date to termination. For
Mr. Jipping, pursuant to the Jipping Letter Agreement, upon a voluntary termination of employment, his
SBUs, which would otherwise be forfeited, will continue to vest on their normal schedule.

(8) Under the 2017 Omnibus Plan, outstanding and unvested PBU awards and respective dividend equivalents
accelerate on a prorated basis under a Change in Control (as defined in the 2017 Omnibus Plan), based
on 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 (as defined in the 2017
Omnibus Plan). In the case of Death or Disability termination, 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. Values shown in the tables above are
based on target performance as an estimate of potential payments. In the case of Retirement or Involuntary
Termination Without Cause within one year of the award grant date, outstanding and unvested PBU awards
and respective dividend equivalents shall be deemed to be forfeited. If Retirement or Involuntary Termination
Without Cause occurs one year or more after the grant date, PBU awards and respective dividend equivalents
shall be deemed to have vested pro-rata based on the period served from grant date to termination. For Mr.
Jipping, pursuant to the Jipping Letter Agreement, upon a voluntary termination of employment, his PBUs,
which would otherwise be forfeited, will continue to vest on their normal schedule. The table does not reflect
any value for Mr. Jipping’s outstanding and unvested PBUs as the payout is subject to achievement of the
performance measures.

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.

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Pay Ratio

As required by the U.S. Congress under 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 2019, our last completed fiscal year:

the median of the annual total compensation of all employees of the Company (other than Ms. Apsey), was

$155,054; and

the annual total compensation of Ms. Apsey as reported in the Summary Compensation Table was

$4,586,704.

Based on this information, Ms. Apsey’s 2019 annual total compensation was estimated to be 30 times the median

annual total compensation for all employees, other than Ms. Apsey.

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. Since our previous year’s pay ratio disclosure there have been no
such changes that would impact our previous pay ratio disclosure and, as a result, we have used the same “median
employee” identified in our previous year’s disclosure.

Using our “median employee” and Ms. Apsey, we calculated the 2019 Summary Compensation Table values for

each according to 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 2019.

Non-Employee Director Compensation Table

Name

(a)

Fees Earned or
Paid in Cash ($)
(1)

(b)

132,500

66,250

—

132,500

143,750

132,500

143,750

170,000

Total ($)

(h)

132,500

66,250

—

132,500

143,750

132,500

143,750

170,000

Robert A. Elliott

Albert Ernst

Rhys D. Evenden (2)

Alexander I. Greenbaum (3)

James P. Laurito

Barry V. Perry

Sandra E. Pierce

Kevin L. Prust

A. Douglas Rothwell

Thomas G. Stephens

Joseph L. Welch

____________________________

(1) Includes annual Board retainer and committee chairmanship retainer, as well as a chairman fee (for Mr.

Welch only).

(2) The fees payable to Mr. Evenden are made directly to Betchworth Investment Pte. Ltd. Mr. Evenden left

the Board in July 2019.

(3) Mr. Greenbaum joined the Board in July 2019. Mr.Greenbaum waived all compensation due to him for

his service on the Board.

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 $132,500. In addition, we pay an additional cash retainer

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of $11,250 annually to the chair of each Board committee and $37,500 annually to our chairman. 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. Messrs. Laurito, Stephens and Ms. Pierce participate in this plan.

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, 2020, 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, 2020 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:

Number of
Fortis shares
Beneficially
Owned (#)

Percent
of Class
(%)

Percent of
Class (%)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—

53,889
12,929
120,000
72,621
—
—
13,597 (1)
—
19,408

840,134 (2)
—
—
—
2,098
1,178,328 (3)

—% 2,313,004

* Less than one percent

*
*
*
*
—
—
*
—
*
*
—
—
—
*
*

Name of Beneficial Owner

Linda H. Apsey
Gretchen L. Holloway
Jon E. Jipping
Daniel J. Oginsky
Christine Mason Soneral
Robert A. Elliott
Albert Ernst
Alexander I. Greenbaum
James P. Laurito
Barry V. Perry
Sandra E. Pierce
Kevin L. Prust
A. Douglas Rothwell
Thomas G. Stephens
Joseph L. Welch
All current directors and executive officers as a group
(16 persons)

Number of
Company
Shares
Beneficially
Owned (#)

—
—
—
—
—
—
—
—
—
—
—
—
—
—
—

—

____________________________

(1)

Includes 4,234 shares owned by the spouse of Mr. Ernst.

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(2)

Includes 31,258 shares owned by the spouse of Mr. Perry as well as 519,462 shares
that may be acquired upon exercise of options that are currently exercisable or
become exercisable prior to April 2, 2020.

(3) The amount shown in the table does not include 534,064 shares beneficially owned by
the spouse of Mr. Welch. Mr. Welch has no voting or dispositive power with respect to
such shares and he disclaims ownership of such shares.

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, 2019, there were no securities authorized for issuance under any compensation plans of

ITC Holdings.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.

CERTAIN TRANSACTIONS

Pursuant to its charter, the Governance and Human Resources Committee is charged with monitoring and
reviewing issues involving independence and potential conflicts of interest with respect to our directors and
executive officers. The Committee also determines whether or not a particular relationship serves the best interest
of the Company and its shareholder and whether the relationship should be continued or eliminated. In addition,
our Code of Conduct and Ethics generally forbids conflicts of interest unless approved by the Board or a designated
committee.

Although the Company does not have a written policy with regard to the approval of transactions between the
Company and its executive officers and directors, each director and officer must annually submit a form to the
General Counsel disclosing his or her conflicts or potential conflicts of interest or certifying that no such conflicts
of interest exist. Throughout the year, if any transaction constituting a conflict of interest arises or circumstances
otherwise change that would cause a director’s or officer’s annual conflict certification to become 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.

Clayton Welch, Jennifer Welch, Jessica Uher and Katie Welch (each of whom is a son, daughter or daughter-
in-law of Joseph L. Welch, the Company’s Chairman) were employed by us as a Senior Engineer, Fleet Manager,
Manager of Corporate and Field Facilities, and Senior Accountant, respectively, during 2019 and continue to be
employed by us. These individuals are employed on an “at will” basis and compensated on the same basis as our
other employees of similar function, seniority and responsibility without regard to their relationship with Mr. Welch.
These four individuals, none of whom resides with or is supported financially by Mr. Welch, received aggregate
salary, bonus, long-term incentives and taxable perquisites for services rendered in the above capacities totaling
$568,001 during 2019.

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 Ms. Pierce and Messrs. Elliott, Ernst, Prust, Rothwell and Stephens 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 defined in
the Shareholders Agreement. None of the directors determined to be independent is or ever has been employed
by us. The Company has made charitable contributions of less than $1 million each to organizations with which
certain of our directors have affiliations. The Board determined that these contributions would not interfere with
the exercise of independent judgment by these directors in carrying out their responsibilities.

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

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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.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.

The following table provides a summary of the aggregate fees incurred for Deloitte’s services in 2019 and 2018:

Audit fees (1)
Audit-related fees (2)
Tax fees (3)
All other fees (4)

Total fees

____________________________

2019
1,901,000 $
54,000
208,000
9,000
2,172,000 $

2018
1,813,000
97,000
386,000
139,000
2,435,000

(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
securities offerings.

(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, attendance at Deloitte sponsored conferences
and labs, and due diligence work in 2018.

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 2019 pursuant to the pre-

approval policy.

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ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.

PART IV

(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, 2019 and 2018

Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2019, 2018 and 2017
Consolidated Statements of Changes in Stockholder's Equity for the Years Ended December 31, 2019, 2018 and

2017

Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 2018 and 2017

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)

Sixth Amended and Restated Bylaws of ITC Holdings Corp (filed with Registrant’s Form 8-K on October
12, 2016)

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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Exhibit No.

Description of Exhibit

4.12

4.14

4.17

4.18

4.19

4.20

4.23

4.24

4.25

4.26

4.27

4.28

4.29

4.30

4.31

4.32

4.33

4.34

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)

Second Supplemental Indenture, dated as of December 15, 2008, 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, to the First Mortgage and Deed of Trust, dated as of January 14, 2008 (filed with
Registrant’s Form 8-K on December 23, 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)

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Exhibit No.

Description of Exhibit

4.35

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

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)

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).

*10.27

10.51

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 2008 Form 10-K)

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Exhibit No.

Description of Exhibit

*10.109

*10.110

*10.111

*10.120

*10.122

*10.150

*10.168

*10.172

*10.173

*10.176

*10.177

*10.178

*10.179

10.182

10.183

10.184

10.185

10.186

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)

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)

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)

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)

Recoupment Policy and Related Consent, effective January 1, 2014 (filed with Registrant’s Form 8-K on
December 2, 2013)

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)

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)

Employment Agreement between ITC Holdings Corp. and Gretchen L. Holloway, effective as of February
3, 2015. (filed with Registrant’s 2016 Form 10-K)

Amended Employment Agreement, dated as of October 12, 2016 between ITC Holdings Corp. and
Christine Mason Soneral (filed with Registrant’s 2016 Form 10-K)

2017 Omnibus Plan, effective February 27, 2017 (filed with Registrant’s Form 10-Q for the quarter
ended March 31, 2017)

Summary of 2017 Annual Incentive Plan (filed with Registrant’s Form 10-Q for the quarter ended March
31, 2017)

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)

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)

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)

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)

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)

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Exhibit No.

10.187

10.188

*10.190

*10.191

*10.192

10.193

10.194

10.195

10.196

Description of Exhibit

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)

International Transmission Company Executive Deferred Compensation Plan, effective January 1, 2019
(filed with Registrant’s 2018 Form 10-K)

ITC Holdings Corp. Director Deferred Compensation Plan, effective January 1, 2019 (filed with Registrant’s
2018 Form 10-K)

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).

Term Loan Credit Agreement, dated as of June 12, 2019, among ITC Holdings Corp., the various financial
institutions and other persons from time to time parties thereto as lenders and Toronto-Dominion (Texas)
LLC, as administrative agent for the Lenders, Mizuho Bank, Ltd. and TD Securities (USA) LLC, as joint
lead arrangers and joint bookrunners and Mizuho Bank, Ltd., as syndication agent (filed with the
Registrant’s Form 8-K on June 14, 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 the Registrant’s Form 8-K on January 10, 2020).

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 the 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 the Registrant’s
Form 8-K on January 10, 2020).

127

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Exhibit No.

10.197

10.198

10.199

*10.200

*10.201

*10.202

31.1

31.2

Description of Exhibit

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 the 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 the Registrant’s Form 8-K on January 10, 2020).

Term Loan Credit Agreement, dated as of January 23, 2020, among Michigan Electric Transmission
Company, LLC, the various financial institutions and other persons from time to time parties thereto as
lenders and Toronto Dominion (Texas) LLC, as administrative agent for the lenders and TD Securities
(USA) LLC, as sole lead arranger and bookrunner (filed with the Registrant’s Form 8-K on January 23,
2020).

2017 Omnibus Plan, as amended July 10, 2017 and February 4, 2020.

Executive Omnibus Plan, effective January 2020.

Form of Performance-Based Unit Award Agreement under Executive Omnibus Plan (January 2020).

List of Subsidiaries

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

Certification 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, 2019,
formatted in Inline XBRL

____________________________

Management contract or compensatory plan or arrangement.

128

Table of Contents

SCHEDULE I — Condensed Financial Information of Registrant

ITC HOLDINGS CORP.

CONDENSED STATEMENTS OF FINANCIAL POSITION (PARENT COMPANY ONLY)

(In millions, except share data)
ASSETS

Current assets

Cash and cash equivalents

Accounts receivable from subsidiaries

Intercompany tax receivable from subsidiaries

Income tax receivable

Prepaid and other current assets

Total current assets

Other assets

Investment in subsidiaries

Deferred income taxes

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

December 31,

2019

2018

—

5,136

140

5,375

5,402

200

293

4,733

104

4,927

4,973

—

Long-term debt (net of deferred financing fees and discount of $17 and $20, respectively)

2,767

STOCKHOLDER’S EQUITY

Common stock, without par value, 235,000,000 shares authorized, 224,203,112 shares issued and

outstanding at December 31, 2019 and 2018

Retained earnings

Accumulated other comprehensive income

Total stockholder’s equity

892

1,333

2,232

TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY

5,402

See notes to condensed financial statements (parent company only).

892

1,155

2,051

4,973

129

Table of Contents

SCHEDULE I — Condensed Financial Information of Registrant

ITC HOLDINGS CORP.

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (PARENT COMPANY ONLY)

(In millions)
Other income (expense), 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 $1 for the year ended December 31, 2019 and

less than $1 for the year ended December 31, 2018)

TOTAL OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX

Year Ended December 31,
2018

2017

2019

(25)

(2)

(119)

(141)

(44)

(97)

525

428

(7)

—

(114)

(120)

(30)

(90)

420

330

TOTAL COMPREHENSIVE INCOME

431

331

See notes to condensed financial statements (parent company only).

(11)

(2)

(120)

(131)

(6)

(125)

444

319

—

319

130

Table of Contents

SCHEDULE I — Condensed Financial Information of Registrant
ITC HOLDINGS CORP.
CONDENSED STATEMENTS OF CASH FLOWS (PARENT COMPANY ONLY)

(In millions)
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 (to) subsidiaries
Other
Changes in assets and liabilities, exclusive of changes shown separately:

Accounts receivable from subsidiaries
Intercompany tax receivable from subsidiaries
Income tax receivable
Intercompany tax payable to subsidiaries
Accrued compensation
Other current and non-current assets and liabilities, net

Net cash used in operating activities
CASH FLOWS FROM INVESTING ACTIVITIES

Equity contributions to subsidiaries
Return of capital from subsidiaries
Other

Net cash provided by investing activities
CASH FLOWS FROM FINANCING ACTIVITIES

Issuance of long-term debt, net of discount
Borrowings under revolving credit agreement
Borrowings under term loan credit agreements
Net issuance of commercial paper, net of discount
Retirement of long-term debt — including extinguishment of debt costs
Repayments of revolving credit agreement
Repayments of term loan credit agreement
Dividends to ITC Investment Holdings
Other

Net cash (used in) provided by financing activities

Year Ended December 31,
2018

2017

2019

428

330

319

(525)
3
(51)
14
6

9
11
1
—
31
9
(64)

(120)
239
(1)
118

—
72
200
200
(203)
(75)
—
(250)
—
(56)
(2)

(420)
26
(23)
59
2

(4)
(13)
14
—
2
13
(14)

(202)
324
(1)
121

—
37
—
—
—
—
—
(200)
(1)
(164)
(57)
61
4

(444)
3
67
(13)
5

(4)
2
2
(72)
14
—
(121)

(148)
296
(9)
139

999
97
200
(148)
(437)
(170)
(200)
(300)
(2)
39
57
4

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

See notes to condensed financial statements (parent company only).

131

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 credit agreement. ITC Holdings may not be able to access cash
generated by our subsidiaries in order to fulfill cash commitments. The ability of our subsidiaries to make dividend
and other payments to us is subject to the availability of funds after taking into account their respective funding
requirements, the terms of their respective indebtedness, the regulations of the FERC under the FPA and applicable
state laws. In addition, there are practical limitations on using the net assets of each of our Regulated Operating
Subsidiaries as of December 31, 2019 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, 2019, the maturities of our debt outstanding were as follows:

(In millions)
2020
2021
2022
2023
2024
2025 and thereafter

Total

200
200
534
250
400
1,400
2,984

Refer to Note 11 to the consolidated financial statements for additional information on the ITC Holdings Senior
Notes, the ITC Holdings Revolving and Term Loan Credit Agreements, the ITC Holdings Commercial Paper Program
and the ITC Holdings Derivative Instruments and Hedging Activities.

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
$2,752 million and $2,764 million at December 31, 2019 and 2018, respectively. The total book value of the ITC
Holdings Senior Notes, net of discount and deferred financing fees, was $2,533 million and $2,730 million at
December 31, 2019 and 2018, respectively. At December 31, 2019 and 2018, we had $234 million and $37 million
respectively, outstanding under our revolving and term loan 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. At December 31, 2019, ITC Holdings had interest rate
swaps with a total notional amount of $200 million, and the fair value of these interest rate swaps of $3 million was
recorded in other current assets in the condensed statements of financial position. The fair values of the ITC
Holdings Senior Notes, revolving and term loan credit agreements and interest rate swaps represent Level 2 under
the three-tier hierarchy described in Note 14 to the consolidated financial statements. At December 31, 2019 ITC
Holdings had $200 million commercial paper issued and outstanding under the commercial paper program. At
December 31, 2018 ITC Holdings had no commercial paper issued and outstanding under the commercial paper
program. Due to the short-term nature of these financial instruments, the carrying value approximates fair value.

132

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3. RELATED-PARTY TRANSACTIONS

Our related-party transactions during were as follows:

(In millions)

Equity contributions to subsidiaries

Dividends from subsidiaries (a)

Return of capital from subsidiaries (a)

Net income tax payments (to) from: (b)

ITCTransmission

METC

ITC Midwest

ITC Great Plains

ITC Interconnection

Other (c)

Year Ended December 31,

2019

2018

2017

120 $

202 $

239

324

7 $

39 $

(1)

—

148

296

(35)

____________________________

(a) Includes ITCTransmission, MTH, ITC Midwest and other subsidiaries.

(b) 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.

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.

Intercompany Tax Sharing Arrangement

As discussed in Note 1 to the condensed financial statements of the parent company, we are a holding company
with no business operations. 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.

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.

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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)
Cash and cash equivalents
Restricted cash included in:
Other non-current assets

Total cash, cash equivalents and restricted cash

December 31,

2019

2018

2017

2016

2 $

3 $

60 $

—
2 $

1
4 $

61 $

—
4

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.

Year Ended December 31,
2018

2017

2019

117 $
3

—

117 $

—

115
1

(2)

Supplementary Cash Flows Information

(In millions)
Supplementary cash flows information:

Interest paid
Income tax refunds received

Supplementary non-cash investing and financing activities:

Equity transfers from subsidiaries

ITEM 16. FORM 10-K SUMMARY.

Not applicable.

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Table of Contents

Pursuant to the requirements of Section 13 or 15(d) the Securities Exchange Act of 1934, the registrant has
duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized in the City of Novi,
State of Michigan, on February 12, 2020.

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, this report has been signed by the following

persons on behalf of the registrant and in the capacities and on the dates indicated:

Signature

Title

/s/ LINDA H. APSEY
Linda H. Apsey

President and Chief Executive
Officer (principal executive officer)

Date

February 12, 2020

/s/ GRETCHEN L. HOLLOWAY
Gretchen L. Holloway

Senior Vice President and Chief Financial Officer
(principal financial and accounting officer)

February 12, 2020

/s/ JOSEPH L. WELCH
Joseph L. Welch

/s/ ROBERT A. ELLIOTT
Robert A. Elliott

/s/ ALBERT ERNST
Albert Ernst

/s/ ALEXANDER I. GREENBAUM
Alexander I. Greenbaum

/s/ JAMES P. LAURITO
James P. Laurito

/s/ BARRY V. PERRY
Barry V. Perry

/s/ SANDRA E. PIERCE
Sandra E. Pierce

/s/ KEVIN L. PRUST
Kevin L. Prust

/s/ A. DOUGLAS ROTHWELL
A. Douglas Rothwell

/s/ THOMAS G. STEPHENS
Thomas G. Stephens

Director and Chairman

February 12, 2020

Director

135