ITC Annual Report 2017 | Quarterlytics

FY2017 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, 2017

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

Commission File Number: 001-32576

ITC HOLDINGS CORP.

(Exact Name of Registrant as Specified in Its Charter)

Michigan
(State or Other Jurisdiction of
Incorporation or Organization)

32-0058047
(I.R.S. Employer
Identification No.)

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

Title of Each Class
Common stock, without par value

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 of 1933. Yes

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of

1934. 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 and posted on its corporate Web site, if any, every Interactive Data
File required to be submitted and posted 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 and post such files). Yes

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of the registrant’s knowledge, in definitive proxy or information, statements incorporated by reference in Part III of this Form 10-K or
any amendment to this Form 10-K.

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

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller Reporting

Company

Emerging growth

company

(Do not check if a smaller
reporting 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, 2017 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 14, 2018.

None

DOCUMENTS INCORPORATED BY REFERENCE

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ITC Holdings Corp.

Form 10-K for the Fiscal Year Ended December 31, 2017

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

126

127

128

129

142

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DEFINITIONS

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

ITC Holdings Corp. and its subsidiaries

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

Development, LLC;

• “ITC Grid Development” are references to ITC Grid Development, 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 Grid

Development, LLC;

• “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 an indirect 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

• “ADIT” are references to accumulated deferred income tax;

• “AFUDC” are references to an allowance for the cost of equity and borrowings used during construction;

• “Ancillary Services Agreement” are references to the Amended and Restated Purchase and Sale Agreement

for Ancillary Services entered into by METC and Consumers Energy dated as of April 29, 2002;

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

• “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;

• “DCF” are references to discounted cash flow;

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

• “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;

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

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

• “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;

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• “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 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;

• “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 October 1, 2016;

• “GIC” are references to GIC Private Limited;

• “GIOA” are references to the Generator Interconnection and Operation Agreement entered into by DTE

Electric and ITCTransmission dated as of February 28, 2003;

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

regarding ROE;

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

of Fortis;

• “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;

• “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 6, 2013;

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

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

• “Merger” are references to the merger with Fortis, whereby ITC Holdings merged with Merger Sub and

subsequently became a majority owned indirect subsidiary of Fortis;

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

Sub and ITC Holdings for the Merger;

• “Merger Sub” are references to Element Acquisition Sub, Inc., an indirect subsidiary of Fortis that merged

into ITC Holdings in 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 June 1, 2015;

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• “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;

• “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;

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

• “Order 1000” are references to FERC Order No. 1000;

• “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;

• “PARs” are references to Phase Angle Regulating Transformers;

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

• “PCBs” are references to polychlorinated biphenyls;

• “ROE” are references to return of equity;

• “RPGI” are references to Resale Power Group of Iowa;

• “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 ROE;

• “September 2016 Order” are references to an order issued by the FERC on September 28, 2016 regarding

ROE complaints;

• “Shareholders Agreement” are references to the Shareholders’ Agreement, dated as of October 14, 2016
by and among the Company, Investment Holdings, FortisUS, Eiffel (as successor to Finn Investment Pte
Ltd), and any other person that becomes a shareholder of 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;

• “Standard and Poor’s” are references to Standard and Poor’s Ratings Services;

• “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 owners; and

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

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EXPLANATORY NOTE

On October 14, 2016, ITC Holdings became a wholly-owned subsidiary of Investment Holdings upon the closing
of the Merger. On the same date, the common shares of ITC Holdings were delisted from the NYSE. As a result,
there is limited share data, and no per share data, presented in this Form 10-K. Refer to Note 2 to the consolidated
financial statements for further details regarding the Merger.

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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. 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. We also are
pursuing development projects not within our existing systems, which are also intended to improve overall grid
reliability, reduce transmission constraints and facilitate interconnections of new generating resources, as well as
enhance competitive wholesale electricity markets. We own and operate high-voltage 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 systems.

As electric transmission utilities 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. The rates
charged by our Regulated Operating Subsidiaries are established using cost-based formula rates, 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.”

The Merger

On February 9, 2016, ITC Holdings entered into the Merger Agreement with Fortis, FortisUS and Merger Sub.
On April 20, 2016, Fortis reached a definitive agreement with GIC for GIC to acquire an indirect 19.9% equity
interest in ITC Holdings upon completion of the Merger. On October 14, 2016, ITC Holdings and Fortis completed
the Merger contemplated by the Merger Agreement. On the same date, the common shares of ITC Holdings were
delisted from the NYSE and the common shares of Fortis were listed and began trading on the NYSE. Fortis
continues to have its shares listed on the Toronto Stock Exchange. As a result of the Merger, Merger Sub merged
with and into ITC Holdings with ITC Holdings continuing as the surviving corporation and becoming a majority
owned indirect subsidiary of FortisUS. In the Merger, ITC Holdings shareholders received $22.57 in cash and
0.7520 Fortis common shares for each share of common stock of ITC Holdings. Refer to Note 2 to the consolidated
financial statements for further details on the Merger.

Development of Business

We are actively developing 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 $2.8 billion from 2018 through 2022 at our Regulated Operating Subsidiaries.
Included in this amount are capital expenditures to: (1) maintain and replace the current transmission infrastructure;
(2) enhance system integrity and reliability and accommodate load growth; and (3) develop and build regional
transmission infrastructure, including additional transmission facilities that will provide interconnection opportunities
for generating facilities.

Development Projects

Through our development activities, we are actively pursuing projects in North America to upgrade the existing
transmission grid and regional transmission facilities, primarily to improve overall grid reliability, reduce transmission
constraints, 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 energy storage and contracted transmission projects.

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Segments

We have one reportable segment consisting of our Regulated Operating Subsidiaries. Additionally, we have
other subsidiaries focused primarily on business development activities and a holding company whose activities
include corporate debt financings and certain other corporate activities. A more detailed discussion of our reportable
segment, including financial information about the segment, is included in Note 18 to the consolidated financial
statements.

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 their 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;

• maintenance; and

• 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 would address potential future reliability issues and/or
produce economic savings for customers by eliminating constraints.

The Asset Planning group works closely with MISO and SPP in the development of our system expansion
capital plans by performing technical evaluations and detailed studies. As the regional planning authorities, MISO
and SPP approve regional system improvement 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 engineering for capital, operation 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.

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 facility in Novi, 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 facility in Novi,
Michigan, our employees perform the LBA functions as outlined in MISO’s Balancing Authority Agreement. These

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functions include actual interchange data administration and verification as well as MECS LBA area emergency
procedure implementation and coordination. Besides ITCTransmission and METC, our other Regulated Operating
Subsidiaries are not responsible for LBA functions for their respective assets.

Operating Contracts

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

ITCTransmission

DTE Electric operates 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.

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

ITC Midwest

IP&L operates 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 parties’
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 was formed to pursue transmission investment opportunities and acquire certain
transmission assets from a merchant generating company and placed a newly constructed 345kV transmission
line in service. As a result, ITC Interconnection became a transmission owner in PJM Interconnection, a FERC-
approved RTO, 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.
After the 2003 blackout that affected sections of the Northeastern and Midwestern United States and Ontario,
Canada, the DOE established the Office of Electric Transmission and Distribution (now the Office of Electricity
Delivery and Energy Reliability), focused 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 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

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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
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.
The open access policy promulgated by the FERC in Order No. 888 was upheld in a United States Supreme Court
decision, State of New York vs. FERC, issued on March 4, 2002. To facilitate open access, among other things,
FERC 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 December 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.

Order 1000 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. With respect to transmission planning, Order 1000: (1) requires that
each public utility transmission provider participate in a regional transmission planning process that produces a
regional transmission plan; (2) requires that each public utility transmission provider amend its Open Access
Transmission Tariff to describe procedures that provide for the consideration of transmission needs driven by public
policy requirements in the local and regional transmission planning processes; (3) removes a federal right of first
refusal for certain new transmission facilities from FERC-approved tariffs and agreements; and (4) improves
coordination between neighboring transmission planning regions for new interregional transmission facilities. MISO
and SPP are compliant with the regional and interregional requirements of Order 1000 after making multiple
compliance filings at the FERC.

Order 1000 could potentially lead to greater competition for certain future transmission projects, including within
our current operating areas. As a part of our identification of incremental development opportunities as it relates
to our plans, we are exploring opportunities resulting from Order 1000 within MISO and SPP as well as other RTOs.

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 are growing as a result of projects
that have been identified by MISO or SPP as having regional benefits, and therefore eligible for regional cost

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recovery under their tariffs. 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 and the Thumb Loop Project in Michigan.
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.

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 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.

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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.

Wisconsin

ITC Midwest is a “public utility” and independent transmission owner in Wisconsin. The Public Service
Commission of Wisconsin in a May 2014 order granted ITC Midwest a certificate of authority to transact public
utility business in the state. In a separate May 2014 order, the Public Service Commission of Wisconsin also
recognized ITC Holdings Corp. 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” in Kansas and an “electric utility” pursuant to state statutes. The Kansas
Corporation Commission 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 Kansas Corporation Commission 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 — Results

of Operations — Operating Revenues” for a discussion of our principal sources of revenue.

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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 22.1%, 21.3% and 25.7%, respectively, of our consolidated billed revenues for the year ended
December 31, 2017. 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 2015 revenue accruals and deferrals and exclude any amounts for the
2017 revenue accruals and deferrals that were included in our 2017 operating revenues, but will not be billed to
our customers until 2019. Refer to “Item 7 Management’s Discussion and Analysis of Financial Condition and
Results of Operations — Cost-Based Formula Rates with True-Up Mechanism” for a discussion on the difference
between billed revenues and operating revenues. Our remaining revenues were generated from providing service
to other entities such as alternative electricity 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, the competitive environment is evolving
due to the implementation of Order 1000. See further discussion of Order 1000 above under “Regulatory
Environment — Federal Regulation.” For our subsidiaries focused on development opportunities for transmission
investment in other service areas, the incumbent utilities or 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.

Employees

As of December 31, 2017, we had 669 employees. We consider our relations with our employees to be good.

Environmental Matters

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as claims for personal injury or property damage, may arise at many locations, including formerly owned or operated
properties and sites where wastes have been treated or disposed of, as well as properties 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 position 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.

Filings Under the Securities Exchange Act of 1934

Our internet address is http://www.itc-holdings.com. 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. Our website also has
posted our Code of Conduct and Ethics.

To learn more about us, please visit our website at http://www.itc-holdings.com. We use our website as a channel
of distribution of material company information. Financial and other material information regarding us is routinely
posted on our website and is readily accessible. The information on our website is not incorporated by reference
into this report.

The public may also read and copy any materials that we file with the SEC at the SEC’s Public Reference Room
at 100 F Street, NE, Washington DC, 20549. Information on the operation of the Public Reference Room may be
obtained by calling the SEC at 1-800-SEC-0330. The SEC also maintains a website that contains reports, proxy
and information statements and other information regarding issuers that file electronically with the SEC. The internet
address is http://www.sec.gov.

ITEM 1A. RISK FACTORS.

Risks Related to Our Business

Certain elements of our Regulated Operating Subsidiaries’ formula rates can be and have been
challenged, which could result in lowered rates and/or refunds of amounts previously collected and thus
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

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parties may challenge the annual implementation and calculation by our Regulated Operating Subsidiaries of their
projected rates and formula rate true up pursuant to their approved formula rates under the Regulated Operating
Subsidiaries’ formula rate implementation protocols. End-use consumers and entities supplying electricity to end-
use consumers may also attempt to influence government and/or regulators to change the rate setting
methodologies that apply to our Regulated Operating Subsidiaries, particularly if rates for delivered electricity
increase substantially. If a challenger can establish that any of these aspects are unjust, unreasonable, unduly
discriminatory or preferential, then the FERC will make appropriate prospective 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.

In November 2013 and February 2015, certain parties filed complaints with the FERC under Section 206 of the
FPA, requesting that the FERC find the base rate of return on equity for all MISO transmission owners, including
ITCTransmission, METC and ITC Midwest, to be unjust and unreasonable. In December 2015, the presiding
administrative law judge issued an initial decision on the Initial Complaint recommending to the FERC a reduction
in the base rate of return on equity of the MISO Transmission owners from 12.38% to 10.32%, with a maximum
rate of 11.35%. In September 2016, the FERC issued an order affirming the presiding administrative law judge's
initial decision, with the new rates to become effective immediately and for the period from November 12, 2013
through February 11, 2015. During the year ended December 31, 2017, we provided net refunds related to the
Initial Complaint, with interest, which were substantially finalized during the second quarter of 2017. All parties
have filed motions for rehearing on various aspects of the September 2016 Order, the FERC’s decision remains
subject to change and the timing of further FERC action is uncertain.

On June 30, 2016, the presiding administrative law judge issued an initial decision on the Second Complaint,
which recommended a base rate of return on equity of 9.70%, which would be applicable for the period from
February 12, 2015 through May 11, 2016 and going forward from the date on which the FERC issues an order on
the Second Complaint, with a maximum rate of 10.68%. In resolving the Second Complaint, we expect the FERC
to establish a new base rate and zone of reasonable returns that will be used, along with any incentive adders, to
calculate the refund liability for the period from February 12, 2015 through May 11, 2016 and the rate going forward
from the date on which the FERC issues an order. An April 2017 decision by the U.S. Court of Appeals for the
District of Columbia Circuit in connection with the establishment of a new base ROE for TOs in ISO New England
may affect the FERC decisions on the Initial Complaint and Second Complaint. In light of the April 2017 court
decision, the MISO TOs filed a motion to dismiss the Second Complaint in September 2017. In 2016 and 2015,
we adjusted revenues downward to accrue for the refund liability based on our estimate of the outcome of these
complaints, which had a negative effect on our results of operations for those periods. The resolution of these
matters may reduce our future revenues and net income and have a further adverse effect on our future results
of operations, cash flows and financial condition.

The TCJA and any future changes in tax laws or regulations may negatively affect our results of
operations, net income, financial condition and cash flows.

We are subject to taxation by various taxing authorities at the federal, state and local levels. 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. In addition, the TCJA provides modifications to bonus depreciation rules and
limitations on the deductibility of interest expense, both of which include carve-outs for regulated utilities.

While certain aspects of the TCJA may be beneficial to ITC, overall we expect the enactment of the TCJA to

adversely affect our results of operations, net income, financial condition and cash flows.

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. The majority of the Company’s deferred tax assets and
liabilities as well as a portion of its federal income tax net operating losses are held at our Regulated Operating
Subsidiaries. The majority of the deferred tax assets and liabilities at the Regulated Operating Subsidiaries are
subject to a normalization method of accounting pursuant to the Internal Revenue Code. As a result, the revaluation
of the Regulated Operating Subsidiaries net deferred taxes generated a net regulatory liability of $512 million and
a reduction in regulatory assets of $65 million at December 31, 2017 that would be returned to or received from
customers over a period of time. The revaluation of the deferred tax assets and federal income tax net operating
losses at ITC Holdings has resulted in additional income tax expense in the fourth quarter of 2017 of $5 million.

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Given the formula rates at our Regulated Operating Subsidiaries, with a reduced corporate tax rate we will
recover and collect lower cash taxes from our customers. Because we are in a federal income tax net operating
loss position and not currently making cash tax payments, the result of this lower recovery is a reduction in cash
flows from operations. Further, we may repost the 2018 projected rate templates for our Regulated Operating
Subsidiaries to reflect the new effective tax rate. Additionally, we may be required to provide a refund for over-
collections from customers from January 1, 2018 through the date of reposting.

The Company has debt at its Regulated Operating Subsidiaries and at ITC Holdings, and the TCJA provides
limitations on the deductibility of interest. While interest deductibility for regulated utilities has been retained, there
is still uncertainty as to whether the holding company debt of a regulated utility will be deductible. If the resolution
of this issue results in limitations in the amount of interest expense that is deductible for ITC Holdings for income
tax purposes, this would have an adverse effect on our net income.

As a result of the changes made to Code Section 162(m) by the TCJA, some of the compensation we provide

to our executive officers may not be deductible in 2018 and going forward.

We cannot predict the timing or impacts of any future changes in tax laws, including the impacts of any subsequent
technical corrections or clarifications. Additionally, certain aspects of the TCJA are still subject to interpretation.
There may be further impacts that materially and adversely affect our results of operations, net income, financial
condition, cash flows, and credit metrics beyond those described herein.

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 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. We anticipate
making significant capital investments over the next several years; however, the amounts could change significantly
due to factors beyond our control. 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 operating subsidiaries may be lower than our published estimates due to, among
other factors, the impact of actual loads, forecasted loads, regional economic conditions, weather conditions, union
strikes, labor shortages, material and equipment prices and availability, 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,
environmental issues, siting, regional planning, cost recovery or other issues, or as a result of legal proceedings
and variances between estimated and actual costs of construction contracts awarded and the potential for greater
competition. 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. Therefore, we can provide no assurance as to
the actual level of investment we may achieve at our operating subsidiaries.

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).

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 transmission owner in MISO or SPP. We cannot predict whether the approved rate methodologies for any of
our Regulated Operating Subsidiaries will be changed. In addition, the U.S. Congress periodically considers
enacting energy legislation that could assign new responsibilities to the FERC, modify provisions of the FPA or
provide the FERC or another entity with increased authority to regulate transmission matters. We cannot predict
whether, and to what extent, 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.

ITCTransmission derives a substantial portion of its revenues from the transmission of electricity to DTE Electric’s
local distribution facilities. DTE Electric accounted for approximately 62.6% of ITCTransmission’s total billed
revenues for the year ended December 31, 2017 and is expected to constitute the majority of ITCTransmission’s
revenues for the foreseeable future. DTE Electric is rated BBB+/stable and A2/stable by Standard and Poor’s
Ratings Services and Moody’s Investors Services, Inc., respectively. Similarly, Consumers Energy accounted for
approximately 77.5% of METC’s total billed revenues for the year ended December 31, 2017 and is expected to
constitute the majority of METC’s revenues for the foreseeable future. Consumers Energy is rated BBB+/stable
and A2/stable by Standard and Poor’s Ratings Services and Moody’s Investors Services, Inc., respectively. Further,
IP&L accounted for approximately 70.7% of ITC Midwest’s total billed revenues for the year ended December 31,
2017 and is expected to constitute the majority of ITC Midwest’s revenues for the foreseeable future. IP&L is rated
A-/stable and Baa1/stable by Standard and Poor’s Ratings Services and Moody’s Investors Services, Inc.,
respectively. These percentages of total billed revenues of DTE Electric, Consumers Energy and IP&L include the
collection of 2015 revenue accruals and deferrals and exclude any amounts for the 2017 revenue accruals and
deferrals that were included in our 2017 operating revenues, but will not be billed to our customers until 2019.

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 their 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.

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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, which, if terminated, could result in a shortage of
a readily available workforce to provide these services. If any of these agreements or arrangements is terminated
for any reason, we may face difficulty finding a qualified replacement work force to provide such services, which
could have an adverse effect on our ability to carry on our business and on our results of operations.

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, inclement weather, natural disasters, mechanical failure, unscheduled downtime, equipment
interruptions, remediation, chemical spills, discharges or releases of toxic or hazardous substances or gases and
other environmental risks. The 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.
Environmental requirements generally have become more stringent in recent years, and compliance with those
requirements more expensive.

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, which 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, the timing of actual collection of our total revenue requirement would likely be delayed until such
circumstances are adjusted through the true-up mechanism in our Regulated Operating Subsidiaries’ formula rates.
In addition, if the revenue requirements of our Regulated Operating Subsidiaries are higher than expected, due
to higher actual expenditures compared to the forecasted expenditures used to develop their billing rates or for

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any other reason, 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 in our Regulated
Operating Subsidiaries' expected formula rates. The effect of such under-collection would be to reduce the amount
of our available cash resources from what we had expected, until such under-collection is corrected through the
true-up mechanism in the formula rate template, which may require us to increase our outstanding indebtedness,
thereby reducing our available borrowing capacity, and may require us to pay interest at a rate that exceeds the
interest to which we are entitled in connection with the operation of the true-up mechanism.

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

The various regulatory requirements to which we are subject include reliability standards established by the
NERC, which acts as the nation’s Electric Reliability Organization approved by the FERC in accordance with
Section 215 of the FPA. These standards address operation, planning and security of the bulk power system,
including requirements with respect to real-time transmission operations, emergency operations, vegetation
management, critical infrastructure protection and personnel training. Failure to comply with these requirements
can result in monetary penalties as well as non-monetary sanctions. Monetary penalties vary based on an assigned
risk factor for each potential violation, the severity of the violation and various other circumstances, such as whether
the violation was intentional or concealed, whether there are repeated violations, the degree of the violator’s
cooperation in investigating and remediating the violation and the presence of a compliance program, and such
penalties can be substantial. Non-monetary sanctions include potential limitations on the violator’s activities or
operation and placing the violator on a watchlist for major violators. Despite our best efforts to comply and the
implementation of a compliance program intended to ensure reliability, there can be no assurance that violations
will not occur that would result in material penalties or sanctions. If any of our subsidiaries were to violate the NERC
reliability standards, even unintentionally, in any material way, any penalties or sanctions imposed against us could
have a material adverse effect on our business, financial condition, results of operations and cash flows.

Certain of our subsidiaries are also subject to requirements under Sections 203 and 205 of the FPA for approval
of transactions; reporting, recordkeeping and accounting requirements; and for filing contracts related to the
provision of jurisdictional services. Under FERC policy, failure to file jurisdictional agreements on a timely basis
may result in foregoing the time value of revenues collected under the agreement, but not to the point 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, cyber 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, cyber 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, terrorist attacks and cyber attacks, as well as natural disasters,
severe weather and other catastrophic events. In addition to any physical damage caused by such events, cyber
attacks targeting our information systems could 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, such events or threats may have a material effect on the economy in general
and could result in a decline in energy consumption, which may have a material adverse effect on our business,
financial condition, results of operations and cash flows.

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Risks Relating to Our Corporate and Financial Structure

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

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

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

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

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

• We may need to increase our indebtedness in order to make the capital expenditures and other expenses

or investments planned by us.

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

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

• We currently have debt instruments outstanding with short-term maturities or relatively short remaining
maturities. Our ability to secure additional financing prior to or after these facilities mature, if needed, may
be substantially restricted by the existing level of our indebtedness and the restrictions contained in our debt
instruments. Additionally, the interest rates at which we might secure additional financings may be higher
than our currently outstanding debt instruments or higher than forecasted at any point in time, which could
adversely affect our business, financial condition, results of operations and cash flows.

• Market conditions could affect our access to capital markets, restrict our ability to secure financing to make
the capital expenditures and investments and pay other expenses planned by us which could adversely
affect our business, financial condition, 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 the TCJA and other statutory or regulatory changes, as well as changes in
our financial performance and unfavorable conditions in the capital markets could result in credit agencies

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reexamining and downgrading our credit ratings. In addition, because we are now 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 net debt to
capitalization ratios and certain funds from operations to net 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 and portions of 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 15 to the consolidated financial statements for more information on the jointly
owned assets.

ITCTransmission owns the assets of a transmission system and related assets, including:

• approximately 3,100 circuit miles of overhead and underground transmission lines rated at voltages of 120

kV to 345 kV;

• approximately 18,700 transmission towers and poles;

• station assets, such as transformers and circuit breakers, at 189 stations and substations which either
interconnect ITCTransmission’s transmission facilities or connect ITCTransmission’s facilities with generation
or distribution facilities owned by others;

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

equipment);

• warehouses and related equipment;

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

• an approximately 198,000 square-foot corporate headquarters facility and operations control room in Novi,

Michigan, including furniture, fixtures and office equipment; and

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• an approximately 40,000 square-foot facility in Ann Arbor, Michigan that includes a back-up operations control

room.

ITCTransmission’s First Mortgage Bonds are issued under ITCTransmission’s first mortgage and deed of trust.
As a result, the bondholders have the benefit of a first mortgage lien on substantially all of ITCTransmission’s
property.

METC owns the assets of a transmission system and related assets, including:

• approximately 5,600 circuit miles of overhead transmission lines rated at voltages of 120 kV to 345 kV;

• approximately 37,500 transmission towers and poles;

• station assets, such as transformers and circuit breakers, at 106 stations and substations which either
interconnect METC’s transmission facilities or connect METC’s facilities with generation or distribution
facilities owned by others;

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

equipment); and

• warehouses and related equipment.

METC's Senior Secured Notes are issued under METC's first mortgage indenture. As a result, the noteholders

have the benefit of a first mortgage lien on substantially all of METC's property.

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.”

ITC Midwest owns the assets of a transmission system and related assets, including:

• approximately 6,600 circuit miles of transmission lines rated at voltages of 34.5 kV to 345 kV;

• transmission towers and poles;

• station assets, such as transformers and circuit breakers, at approximately 278 stations and substations
which either interconnect ITC Midwest’s transmission facilities or connect ITC Midwest’s facilities with
generation or distribution facilities owned by others;

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

equipment);

• warehouses and related equipment; and

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

ITC Midwest’s First Mortgage Bonds are issued under ITC Midwest’s first mortgage and deed of trust. As a

result, the bondholders have the benefit of a first mortgage lien on substantially all of ITC Midwest’s property.

ITC Great Plains owns transmission and related assets including:

• approximately 470 miles of transmission lines rated at a voltage of 345 kV;

• approximately 2,120 transmission towers and poles;

• station assets, such as transformers and circuit breakers, at 9 stations and substations which either
interconnect ITC Great Plains’ transmission facilities or connect ITC Great Plains’ facilities with transmission,
generation or distribution facilities owned by others;

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

equipment); and

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

ITC Great Plains’ First Mortgage Bonds are issued under ITC Great Plains’ first mortgage and deed of trust. As
a result, the bondholders have the benefit of a first mortgage lien on substantially all of ITC Great Plains’ property.

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ITC Interconnection owns certain substation assets and less than a mile of a transmission line rated at a voltage
of 345 kV in Michigan. As of December 31, 2017, 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 5 and 17 to the consolidated financial statements for a description of certain pending legal

proceedings, which description is incorporated herein by reference.

ITEM 4. MINE SAFETY DISCLOSURES.

Not applicable.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND

ISSUER PURCHASES OF EQUITY SECURITIES.

With the consummation of the Merger on October 14, 2016, ITC Holdings became a wholly-owned subsidiary of
Investment Holdings and ITC Holdings’ common stock was delisted from NYSE. Consequently, there is no longer
any public trading market for the common stock of ITC Holdings. Prior to the closing of the Merger, the common
stock of ITC Holdings was traded on the NYSE under the symbol ITC. The following tables set forth the high and
low sales price per share of the common stock for each quarterly period in 2016 (through October 14, 2016), as
reported on the NYSE, and the cash dividends per share paid during the periods indicated.

Year Ended December 31, 2016
October 1 through October 14, 2016
Quarter ended September 30, 2016
Quarter ended June 30, 2016
Quarter ended March 31, 2016

High
46.48
47.46
46.89
43.89

Low
44.91
44.64
42.44
36.53

Dividends
—
0.2155
0.1875
0.1875

Additionally, ITC Holdings paid dividends of $300 million and $33 million to Investment Holdings during the years
ended December 31, 2017 and December 31, 2016, respectively. ITC Holdings also paid dividends of $50 million
to Investment Holdings in January 2018. The debt agreements to which we are a party contain numerous financial
covenants that could limit ITC Holdings’ ability to pay dividends. Further, each of our subsidiaries is legally distinct
from ITC Holdings and has no obligation, contingent or otherwise, to make funds available to ITC Holdings.

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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)
OPERATING REVENUES (a)
OPERATING EXPENSES

Operation and maintenance

General and administrative (b) (c) (d)

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 (e)
Allowance for equity funds used during
construction
Other income
Other expense

Total other expenses (income)

INCOME BEFORE INCOME TAXES
INCOME TAX PROVISION
NET INCOME

(In millions)
BALANCE SHEET DATA:

Cash and cash equivalents

Working capital (deficit) (f)

Property, plant and equipment — net

Goodwill

Total assets (f) (g)

Debt:

ITC Holdings (g)
Regulated Operating Subsidiaries (g)

Total debt (g)
Total stockholder’s equity

(In millions)
CASH FLOWS DATA:

Expenditures for property, plant and

equipment

____________________________

2017

ITC Holdings and Subsidiaries
Year Ended December 31,
2015

2016

2014

2013

1,211

1,125

1,045

1,023

941

110

123

169

103

(2)
503
708

224

(33)

(3)
5
193
515
196
319

2017

114

239

158

(1)
603
522

211

(35)

(2)
5
179
343
97
246

113

145

(1)
484
561

204

(28)

(2)
3
177
384
142
242

112

115

128

(1)
430
593

216

(21)

(1)
5
199
394
150
244

ITC Holdings and Subsidiaries
As of December 31,
2015

2016

2014

113

149

119

(2)
445
496

168

(30)

(1)
7
144
352
119
233

2013

66 $

8 $

14 $

28 $

(302)
7,309
950
8,823

(400)
6,698
950
8,223

(550)
6,110
950
7,555

(291)
5,497
950
6,932

2,728
2,373
5,101
1,920 $

2,387
2,203
4,590
1,901 $

2,304
2,125
4,429
1,709 $

2,123
1,954
4,077
1,670 $

2017

ITC Holdings and Subsidiaries
Year Ended December 31,
2015

2016

2014

34
(325)
4,847
950
6,241

1,871
1,717
3,588
1,614

2013

755 $

750 $

701 $

753 $

824

(a) During 2017, 2016, 2015 and 2014, we recognized an aggregate estimated regulatory liability for the refund
and potential refund relating to the rate of return on equity complaints as described in Note 17 to the consolidated

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financial statements, which resulted in a reduction in operating revenues of $80 million, $115 million and $47
million in 2016, 2015 and 2014, respectively.

(b) During 2016, we expensed external legal, advisory and financial services fees of $55 million related to the
Merger and approximately $41 million due to the accelerated vesting of the share-based awards that occurred
at the completion of the Merger. See Note 2 to the consolidated financial statements for further details on the
impact of the Merger. The external and internal costs related to the Merger were recorded at ITC Holdings and
have not been included as components of revenue requirement at our Regulated Operating Subsidiaries.

(c) The increase in general and administrative expenses in 2015 was due primarily to higher compensation related
expenses, including the development bonuses for the successful completion of certain milestones relating to
projects at ITC Great Plains and higher legal and advisory professional service fees for various development
initiatives which were not included as components of revenue requirement at our Regulated Operating
Subsidiaries.

(d) During 2013, we expensed external legal, advisory and financial services fees of $43 million recorded within
general and administrative expenses related to a proposed transaction whereby the electric transmission
business of Entergy Corporation was to be separated and subsequently merged with a wholly-owned subsidiary
of ITC Holdings. The proposed transaction was terminated in December 2013. The external and internal costs
related to the proposed transaction with Entergy Corporation were recorded at ITC Holdings and were not
included as components of revenue requirement at our Regulated Operating Subsidiaries.

(e) During 2014, we recorded loss on extinguishment of debt of $29 million related to a cash tender offer for the

retirement of debt at ITC Holdings.

(f) All amounts presented reflect the change in the authoritative guidance issued by the Financial Accounting
Standards Board to net all deferred income tax assets and liabilities and present as a single line item within
non-current assets or liabilities on the balance sheet. This change was adopted retrospectively by us in 2015.

(g) All amounts presented reflect the change in authoritative guidance on the presentation of debt issuance costs

on the balance sheet. This change was adopted retrospectively by us in 2015.

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,”
“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.

Overview

Through our Regulated Operating Subsidiaries, we own and operate high-voltage systems in Michigan’s Lower
Peninsula and portions of Iowa, Minnesota, Illinois, Missouri, Kansas and Oklahoma that transmit electricity from

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generating stations to local distribution facilities connected to our 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. We
also are pursuing development projects not within our existing systems, which are also intended to improve overall
grid reliability, reduce transmission constraints and facilitate interconnections of new generating resources, as well
as enhance competitive wholesale electricity markets.

As electric transmission utilities whose rates are regulated by the FERC, our Regulated Operating Subsidiaries
earn revenues for the use of their electric transmission systems by our customers. We derive nearly all of our
revenues from providing electric transmission service over our Regulated Operating Subsidiaries’ transmission
systems to investor-owned utilities, such as DTE Electric, Consumers Energy and IP&L, and other entities, such
as alternative electricity 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.

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 in “Item 7 Management’s Discussion and Analysis
of Financial Condition and Results of Operations — Cost-Based Formula Rates with True-Up Mechanism” as well
as in Note 5 to the consolidated financial statements.

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 position and results of operations and cash flows for the

year ended December 31, 2017 or that may affect future results include:

• Recognition of a net regulatory liability of $512 million and a reduction in regulatory assets of $65 million as
of December 31, 2017 and additional income tax expense of $5 million as a result of the change in corporate
tax rate from 35% to 21% pursuant to the TCJA, as discussed in Note 6 and Note 10 to the consolidated
financial statements, respectively.

• Our capital expenditures of $755 million at our Regulated Operating Subsidiaries during the year ended
December 31, 2017, 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;

• Debt issuances, issuances of commercial paper under ITC Holdings’ commercial paper program, and
borrowings under our revolving and term loan credit agreements, as described in Note 9 to the consolidated
financial statements, to fund capital investment at our Regulated Operating Subsidiaries, repayment of other
indebtedness, and for general corporate purposes;

• Debt maturing within one year of $100 million as of December 31, 2017 and the potentially higher interest
rates associated with the additional financing required to repay this debt as discussed in Note 9 to the
consolidated financial statements;

• During the year ended December 31, 2017, our MISO Regulated Operating Subsidiaries provided net refunds
with interest of $118 million for the Initial ROE complaint, subject to the pending rehearing request. Our MISO
Regulated Operating Subsidiaries have an estimated current regulatory liability recorded for the Second
Complaint of $145 million as of December 31, 2017. For the year ended December 31, 2017, the refund
and estimated refund relating to the rate of return on equity complaints, as described in Note 17 to the
consolidated financial statements, resulted in additional interest expense of $6 million and an estimated
after-tax reduction to net income of $3 million.

These items are discussed in more detail throughout “Item 7 Management’s Discussion and Analysis of Financial

Condition and Results of Operations.”

Cost-Based Formula Rates with True-Up Mechanism

Our Regulated Operating Subsidiaries calculate their revenue requirements using cost-based formula rates
that are effective without the need to file rate cases with the FERC, although the rates are subject to legal challenge
at the FERC. Under their cost-based formula, each of our Regulated Operating Subsidiaries separately calculates

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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 initially
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 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 5 for further discussion of our formula rates
and see “Rate of Return on Equity Complaints” in Note 17 to the consolidated financial statements for detail on
ROE matters.

Illustrative Example of Formula Rate Setting

The formula rate setting example shown below is for illustrative purposes and 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

8.81%

88,100

150,000

50,000

288,100

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

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

Debt
Equity

Percentage of
Total Capitalization
40.00%
60.00%
100.00%

Cost of Capital

5.00% =
11.35% =

Weighted
Average
Cost of
Capital

2.00%
6.81%
8.81%

is not based on our actual tax expense.

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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 and,
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 revenues and earnings, subject to the impact of:

•

any rate changes and required refunds resulting from the resolution of the ROE complaints as described
in Note 17 to the consolidated financial statements;

lower revenue from customers due to a lower tax gross up on our authorized return on equity at our
Regulated Operating Subsidiaries resulting from the change in U.S. federal corporate income tax rate from
35% to 21% under the TCJA; and

•

lower net income due to lower interest expense deductibility at ITC Holdings as a result of the TCJA.

The primary factor that is expected to continue to increase our revenues and earnings in future years is increased
rate base that would result from our anticipated capital investment, in excess of depreciation, 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.

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.

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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) rebuild existing property,
plant and equipment; (2) upgrade the system to address demographic changes that have impacted transmission
load and the changing role that transmission plays in meeting the needs of the wholesale market, including
accommodating the siting of new generation or increasing import capacity to meet changes in peak electrical
demand; (3) relieve congestion in the transmission systems; and (4) achieve state and federal policy goals, such
as renewable generation portfolio standards. 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, 2017
$

755 $

2018 — 2022
2,842

(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 allowance for equity funds used during construction 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 are
not able to estimate the amounts we ultimately expect to invest or the timing of such investments. Our capital
investment efforts relating to development initiatives are based on establishing an ongoing pipeline of projects that
would position us for long-term growth. Refer to “Item 1 Business — Development of Business — Development
Projects” for discussion of our development projects.

Investments in property, plant and equipment could vary due to, among other things, the impact of actual loads,
forecasted loads, regional economic conditions, weather conditions, union strikes, labor shortages, material and
equipment prices and availability, our ability to obtain any necessary financing for such expenditures, limitations
on the amount of construction that can be undertaken on our systems at any one time, regulatory approvals for
reasons relating to rate construct, environmental, siting, regional planning, cost recovery or other issues or as a
result of legal proceedings, variances between estimated and actual costs of construction contracts awarded and
the potential for greater competition for new development projects. 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

2017 Tax Reform

In December 2017, the President of the United States of America 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. We were required to revalue our deferred tax
assets and liabilities at the new federal corporate income tax rate as of the date of enactment of the TCJA. The
majority of our deferred tax assets and liabilities as well as a portion of its U.S. federal net operating losses are
held at our Regulated Operating Subsidiaries. The majority of the deferred tax assets and liabilities at the Regulated
Operating Subsidiaries are subject to a normalization method of accounting pursuant to the Internal Revenue
Code. As a result, the revaluation of the Regulated Operating Subsidiaries net deferred taxes resulted in a net
regulatory liability of approximately $512 million at December 31, 2017 and a reduction in regulatory assets of $65
million that would be returned to or received from customers over a period of time. The revaluation of the deferred
tax assets and federal income tax net operating losses at ITC Holdings has resulted in additional income tax
expense in the fourth quarter of 2017 of $5 million. For additional information on the impacts of tax reform, see
Note 6 and Note 10 to the consolidated financial statements.

The Merger

On February 9, 2016, ITC Holdings entered into the Merger Agreement with Fortis, FortisUS and Merger Sub.
On April 20, 2016, Fortis reached a definitive agreement with a subsidiary of GIC for that subsidiary to acquire an

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indirect 19.9% equity interest in ITC Holdings upon completion of the Merger. On October 14, 2016, ITC Holdings
and Fortis completed the Merger contemplated by the Merger Agreement. On the same date, the common shares
of ITC Holdings were delisted from the NYSE and the common shares of Fortis were listed and began trading on
the NYSE. Fortis continues to have its shares listed on the Toronto Stock Exchange. As a result of the Merger,
Merger Sub merged with and into ITC Holdings with ITC Holdings continuing as the surviving corporation and
becoming a majority owned indirect subsidiary of Fortis. In the Merger, ITC Holdings shareholders received $22.57
in cash and 0.7520 Fortis common shares for each share of common stock of ITC Holdings. Refer to Note 2 to
the consolidated financial statements for further details on the Merger.

Rate of Return on Equity Complaints

In November 2013 and February 2015, certain parties filed complaints with the FERC under Section 206 of the
FPA, requesting that the FERC find the then current MISO regional base ROE rate for all MISO TOs, including
ITCTransmission, METC and ITC Midwest, to no longer be just and reasonable. The complainants sought a FERC
order reducing the base ROE used in the formula transmission rates for our MISO Regulated Operating Subsidiaries.

In September 2016, the FERC issued the September 2016 Order in connection with the Initial Complaint reducing
the base ROE from 12.38% to 10.32%, with a maximum ROE of 11.35%, effective for the period from November
12, 2013 through February 11, 2015 and prospectively from the date of that order until a new approved rate is
established by the FERC in connection with the Second Complaint filed with the FERC under Section 206 of the
FPA on February 12, 2015. The total estimated refund for the Initial Complaint resulting from this FERC order,
including interest, was $118 million for our MISO Regulated Operating Subsidiaries as of December 31, 2016,
recorded in current liabilities on the consolidated statements of financial position. During the year ended December
31, 2017, we provided net refunds with interest, which were substantially finalized during the second quarter of
2017. The total amount of the net refunds, including interest and the associated true-up, for the Initial Complaint
were not materially different from the estimated amount recorded as of December 31, 2016.

An order has not yet been issued by the FERC in connection with the Second Complaint. If the Second Complaint
is not dismissed, we expect the FERC to establish a new base ROE and zone of reasonableness that will be used,
along with any ROE adders, to calculate the liability for the refund period related to the Second Complaint and
future ROEs for our MISO Regulated Operating Subsidiaries. As of December 31, 2017, the estimated range of
refunds for the related refund period is from $106 million to $145 million on a pre-tax basis. Our MISO Regulated
Operating Subsidiaries have recorded an estimated current regulatory liability for the Second Complaint of $145
million as of December 31, 2017. An estimated liability for the Second Complaint of $140 million was recorded as
a non-current regulatory liability as of December 31, 2016. The recognition of the obligations associated with the
complaints resulted in a reduction of revenues and net income and additional interest expense as set forth in the
table below for the periods indicated.

(In millions)

Revenue reduction
Interest expense increase
Estimated net income reduction (a)

____________________________

Year Ended December 31,
2016

2017

2015

— $
6
3

80 $
10
55

115
5
73

(a) Includes an effect on net income of $27 million and $28 million for the year ended December 31, 2016 and

2015, respectively, for revenue initially recognized in 2015, 2014 and 2013.

It is possible that the outcome of these matters could differ from the estimated range of losses and materially
affect our consolidated results of operations due to the uncertainty of the calculation of an authorized base ROE
along with the zone of reasonableness. Further uncertainty regarding the outcome of the Initial Complaint and the
Second Complaint and the timing of completion of these matters has been introduced due to the U.S. Court of
Appeals for the District of Columbia Circuit’s Emera Maine v. FERC decision. Based on the level of aggregate
equity in our MISO Regulated Operating Subsidiaries, we estimate that each 10 basis point reduction in the
authorized ROE would reduce annual consolidated net income by approximately $3 million. In addition, the motion
to dismiss, filed in September 2017, could also affect the resolution of the Second Complaint. For a more detailed
discussion of the ROE complaints, see Note 17 to the consolidated financial statements.

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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 electricity 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 to “Item 7 Management’s Discussion and Analysis of Financial
Condition and Results of Operations — 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.

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.

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 and the
Thumb Loop Project in Michigan. Regional cost sharing revenue also includes revenues collected by transmission
customers from other RTOs outside of MISO to allocate costs of certain transmission plant investments. Additionally,
certain projects at ITC Great Plains are eligible for recovery through a region-wide charge under provisions of the
SPP tariff. A portion of regional cost sharing revenues is treated as a revenue credit to regional or network customers
and is 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.

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Maintenance expenses include preventive or planned maintenance, such as vegetation management, tower

painting and equipment inspections, as well as reactive maintenance for equipment failures.

General and Administrative Expenses consist primarily of costs for personnel in our legal, information
technology, finance, regulatory, human resources 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 refund and estimated refund relating to the 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.

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Results of Operations

The following table summarizes historical operating results for the periods indicated:

(In millions)
OPERATING REVENUES

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

Other expense

Total other expenses (income)

INCOME BEFORE INCOME TAXES

INCOME TAX PROVISION

NET INCOME

Operating Revenues

Year Ended
December 31,

2017

2016

Increase
(Decrease)

Percentage
Increase
(Decrease)

Year Ended
December 31,
2015

Increase
(Decrease)

Percentage
Increase
(Decrease)

1,211

1,125

1,045

110

123

169

103

(2)

503

708

224

(33)

(3)

193

515

196

319

114

239

158

(1)

603

522

211

(35)

(2)

179

343

246

(4)

(4)%

(116)

(49)%

(1)

(100)

186

(1)

—

172

11%

100%

(17)%

36%

(6)%

50%

—%

50%

102%

30%

113

145

(1)

484

561

204

(28)

(2)

3
177

384

142

242

—

119

(39)

(7)

—

(41)

(45)

65%

13%

—%

25%

(7)%

25%

—%

67%

(11)%

(32)%

Year ended December 31, 2017 compared to year ended December 31, 2016

The following table sets forth the components of and changes in operating revenues:

2017

2016

Amount

Percentage

Amount

Percentage

(In millions)
Network revenues

Regional cost sharing revenues

Point-to-point

Scheduling, control and dispatch

Other

Recognition of refund liabilities

Total

816
340
18
14
24
(1)
1,211

67 % $
28 %
2 %
1 %
2 %
— %
100 % $

814
337
20
14
20
(80)
1,125

Increase
(Decrease)
2
3
(2)
—
4
79
86

72 % $
30 %
2 %
1 %
2 %
(7)%
100 % $

Percentage
Increase
(Decrease)

— %
1 %
(10)%
— %
20 %
(99)%
8 %

Although network and regional cost sharing revenues were consistent with the respective prior period, there
was a decrease in revenue requirement due to lower ROEs, which was offset by a higher rate base mainly due to
higher property, plant and equipment.

The recognition of the liability for the refund and estimated refund relating to the ROE complaints, described in
Note 17 to the consolidated financial statements, resulted in a reduction of operating revenues during the year
ended December 31, 2016. We are not able to estimate whether any required refunds would be applied to all
components of revenue listed in the table above or only certain components.

Operating revenues for the years ended December 31, 2017 and 2016 include revenue accruals and deferrals

as described in Note 5 to the consolidated financial statements.

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Year ended December 31, 2016 compared to year ended December 31, 2015

The following table sets forth the components of and changes in operating revenues:

2016

2015

Amount

Percentage

Amount

Percentage

(In millions)
Network revenues

Regional cost sharing revenues

Point-to-point

Scheduling, control and dispatch
Other

Recognition of refund liabilities

Total

814
337
20
14
20
(80)
1,125

72 % $
30 %
2 %
1 %
2 %
(7)%
100 % $

802
328
15
13
12
(125)
1,045

Increase
(Decrease)
12
9
5
1
8
45
80

77 % $
31 %
2 %
1 %
1 %
(12)%
100 % $

Percentage
Increase
(Decrease)

1 %
3 %
33 %
8 %
67 %
(36)%
8 %

Network revenues increased due primarily to higher net revenue requirements at our Regulated Operating
Subsidiaries, partially offset by higher regional revenue requirements, during the year ended December 31, 2016
as compared to 2015. Higher net revenue requirements were due primarily to higher rate bases associated with
higher balances of property, plant and equipment in-service in 2016.

Regional cost sharing revenues increased primarily due to additional capital projects identified by MISO and
SPP as eligible for regional cost sharing and these projects being placed in-service, in addition to higher accumulated
investment for regional cost sharing projects in northern Michigan and Kansas during the year ended December
31, 2016 as compared to the same period in 2015.

The recognition of the liabilities for the refund relating to the formula rate template modifications and the refund
and estimated refund relating to the ROE complaints described in Notes 5 and 17 to the consolidated financial
statements, respectively, resulted in a reduction to operating revenues during the years ended December 31, 2016
and 2015, respectively. We are not able to estimate whether any required refunds would be applied to all components
of revenue listed in the table above or only certain components.

Operating revenues for the years ended December 31, 2016 and 2015 include revenue accruals and deferrals

as described in Note 5 to the consolidated financial statements.

Operating Expenses

Operation and maintenance expenses

Year ended December 31, 2017 compared to the respective period in 2016 and the year ended December 31,

2016 compared to the respective period in 2015

Operation and maintenance expenses were consistent with the respective prior period.

General and administrative expenses

Year ended December 31, 2017 compared to year ended December 31, 2016

General and administrative expenses decreased due to a reduction in professional services related to the
Merger and a reduction in compensation-related expenses primarily due to lower bonuses and stock compensation
expense, including the accelerated vesting of the share-based awards that occurred at the completion of the Merger
in 2016 as described in Note 14 to the consolidated financial statements. The costs related to the Merger were
recorded at ITC Holdings and have not been included as components of revenue requirement at our Regulated
Operating Subsidiaries.

Year ended December 31, 2016 compared to year ended December 31, 2015

General and administrative expenses increased related to higher compensation-related expenses due to
retention bonuses relating to the Merger, personnel additions and additional stock compensation expense, including
the accelerated vesting of the share-based awards that occurred at the completion of the Merger as described in
Note 14 to the consolidated financial statements, and increased expenses related to external legal, advisory and
financial services fees incurred in 2016 related to the Merger. These increases were partially offset by a decrease

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in development bonus expenses, which were not recovered in rates, for the successful completion of certain
milestones relating to projects at ITC Great Plains in 2015.

Depreciation and amortization expenses

Year ended December 31, 2017 compared to the respective period in 2016 and the year ended December 31,

2016 compared to the respective period in 2015

Depreciation and amortization expenses increased in the respective period due primarily to a higher depreciable

base resulting from property, plant and equipment in-service additions.

Taxes other than income taxes

Year ended December 31, 2017 compared to the respective period in 2016 and the year ended December 31,

2016 compared to the respective period in 2015

Taxes other than income taxes increased due to higher property tax expenses primarily due to our Regulated
Operating Subsidiaries’ 2016 and 2015 capital additions, which are included in the assessments for 2017 and 2016
property taxes, respectively.

Other expenses (income)

Year ended December 31, 2017 compared to year ended December 31, 2016

Interest expense increased due primarily to long-term debt issuances subsequent to December 31, 2016 which
resulted in overall higher carrying balances of long-term debt. These issuances were used for refinancing of current
debt maturities as well as general corporate purposes.

Year ended December 31, 2016 compared to year ended December 31, 2015

Interest expense increased due primarily to the additional interest expense associated with the refund liability
relating to the ROE complaints described in Note 17 to the consolidated financial statements and long-term debt
issuances subsequent to December 31, 2015, which were used for refinancing of current debt maturities and
general corporate purposes.

AFUDC equity increased due primarily to higher balances of construction work in progress eligible for AFUDC

equity during the period.

Income Tax Provision

Year ended December 31, 2017 compared to year ended December 31, 2016

Our effective tax rates for the years ended December 31, 2017 and 2016 are 38.1% and 28.3%, respectively.
Our effective tax rate as of December 31, 2017 exceeded our 35% statutory federal income tax rate due primarily
to the enactment of the TCJA and the required revaluation of our deferred tax assets and liabilities from 35% to
21%, partially offset by income tax relating to AFUDC equity as discussed in Note 10 to the consolidated financial
statements. Our effective tax rate as of December 31, 2016 was less than our 35% statutory federal income tax
rate due primarily to us recognizing an income tax benefit of $27 million for excess tax deductions for the year
ended December 31, 2016 as a result of adopting the new accounting guidance associated with share-based
payments as described in Note 10 to the consolidated financial statements. The amount of income tax expense
relating to AFUDC equity was recognized as a regulatory asset and not included in the income tax provision.

Year ended December 31, 2016 compared to year ended December 31, 2015

Our effective tax rates for the years ended December 31, 2016 and 2015 are 28.3% and 36.9%, respectively.
Our effective tax rate as of December 31, 2016 was less than our 35% statutory federal income tax rate due
primarily to us recognizing an income tax benefit of $27 million for excess tax deductions for the year ended
December 31, 2016 as a result of adopting the new accounting guidance associated with share-based payments
as described in Note 10 to the consolidated financial statements. Our effective tax rate as of December 31, 2015
exceeded our 35% statutory federal income tax rate due primarily to state income taxes, partially offset by the tax
effects of AFUDC equity. The amount of income tax expense relating to AFUDC equity was recognized as a
regulatory asset and not included in the income tax provision.

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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 9 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 “Item 7 Management’s Discussion and
Analysis of Financial Condition and Results of Operations — Capital Investment and Operating Results
Trends.”

• Fund business development expenses and related capital expenditures. We are pursuing development
activities for projects that will continue to result in the incurrence of development expenses and could result
in significant capital expenditures incremental to our current plan. Refer to Note 17 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 “Item 7 Management’s Discussion and Analysis of Financial
Condition and Results of Operations — Contractual Obligations.” We expect our interest payments to increase
each year as a result of additional debt expected to be incurred to fund our capital expenditures and for
general corporate purposes.

• Fund any refund obligation in connection with the ROE complaints.

• Fund any possible 2018 refund obligation in connection with the potential reposting of the 2018 rates at the
Regulated Operating Subsidiaries to reflect the change in federal tax rate arising from the enactment of the
TCJA.

• Fund payments related to the amortization through rates of the net regulatory liability recorded for excess
deferred taxes and any other obligations arising from the implementation of the TCJA, as described in Note
6 to the consolidated financial statements.

• Fund contributions to our retirement benefit plans, as described in Note 11 to the consolidated financial

statements. We expect to contribute up to $14 million to these plans in 2018.

In addition to the expected capital requirements above, any adverse determinations or settlements relating to
the regulatory matters or contingencies described in Notes 5 and 17 to the consolidated financial statements would
result in additional capital requirements.

We believe that we have sufficient capital resources to meet our currently anticipated short-term 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
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,
2017, we had consolidated indebtedness under our revolving and term loan credit agreements of $271 million,
with unused capacity under the revolving credit agreements of $679 million. Additionally, ITC Holdings had no
commercial paper issued and outstanding as of December 31, 2017, with the ability to issue $400 million under
the commercial paper program. See Note 9 to the consolidated financial statements for a detailed discussion of
the commercial paper program and our revolving and term loan credit agreements as well as the debt activity
during the years ended December 31, 2017 and 2016.

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As of December 31, 2017, we had approximately $100 million of fixed rate debt maturing within one year, which
we expect to repay with borrowings under our revolving credit agreements or refinance with long-term debt. 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.

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 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.

Issuer

ITC Holdings
ITC Holdings
ITCTransmission
METC
ITC Midwest
ITC Great Plains

Issuance
Senior Unsecured Notes
Commercial Paper
First Mortgage Bonds
Senior Secured Notes
First Mortgage Bonds
First Mortgage Bonds

____________________________

Standard and Poor’s
Ratings Services (a)
A-
A-2
A
A
A
A

Moody’s Investor
Service, Inc. (b)
Baa2
Prime-2
A1
A1
A1
A1

(a) On September 15, 2017, Standard and Poor’s reaffirmed the secured credit ratings of ITCTransmission, METC,
ITC Midwest, ITC Great Plains and the short-term commercial paper rating at ITC Holdings, which applies to
the commercial paper program discussed in Note 9 to the consolidated financial statements. Standard and
Poor’s also reaffirmed the stable outlook for these entities. On September 28, 2017, Standard and Poor’s
raised the senior unsecured credit rating of ITC Holdings to A- from BBB+. On December 20, 2017, Standard
and Poor’s published reports on ITCTransmission, METC and ITC Midwest as part of their annual review
process. No ratings actions were taken in these reports.

(b) On April 12, 2017, Moody’s reaffirmed the senior unsecured credit rating of ITC Holdings, the secured credit
ratings of ITCTransmission, METC, ITC Midwest, ITC Great Plains and the short-term commercial paper rating
at ITC Holdings, which applies to the commercial paper program discussed in Note 9 to the consolidated
financial statements. Moody’s also reaffirmed the stable outlook for these entities.

Covenants

Our debt instruments contain numerous financial and operating covenants that place significant restrictions on
certain transactions as well as require us to meet certain financial ratios, which are described in Note 9 to the
consolidated financial statements. As of December 31, 2017, 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.

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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
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)

Issuance of common stock

Dividends on common and restricted stock

Dividends to ITC Investment Holdings Inc.
Refundable deposits from and repayments to generators for transmission

network upgrades — net

Repurchase and retirement of common stock

Settlement of share-based awards associated with the Merger — including

cost of accelerated share-based awards

Contribution from ITC Investment Holdings Inc. for the settlement of share-

based awards associated with the Merger

Other

Net cash provided by financing activities

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
CASH AND CASH EQUIVALENTS — Beginning of period
CASH AND CASH EQUIVALENTS — End of period

Cash Flows From Operating Activities

Year Ended December 31,
2016

2015

2017

319 $

246 $

242

169

34
195
(109)
608

(755)
11
(744)

511
—
—
(300)

(12)
—

—

—
(5)
194
58
8

158

(2)
219
66
687

(750)
15
(735)

161
13
(90)
(33)

23
(9)

(137)

137
(23)
42
(6)
14

66 $

8 $

145

(54)
77
146
556

(701)
1
(700)

352
14
(108)
—

1
(137)

—

—
8
130
(14)
28
14

Year ended December 31, 2017 compared to year ended December 31, 2016

Net cash provided by operating activities decreased in 2017 compared to 2016. The decrease in cash provided
by operating activities was due primarily to the refund, including interest, pursuant to the September 2016 Order,
and higher interest payments (net of interest capitalized excluding the interest paid as part of the refund noted
above) for the year ended December 31, 2017 compared to the same period in 2016. Additionally, the cash provided
by operating activities was lower during 2017 due to the receipt of an income tax refund from the IRS in August
2016. The decreases were partially offset by an increase in receipts from operating revenues, an increase in the
cash receipts for the regional cost allocation refund in 2017 compared to cash payments in 2016, accelerated
incentive payouts in 2016 associated with the Merger and lower income taxes paid during the year ended December
31, 2017 compared to the same period in 2016.

Year ended December 31, 2016 compared to year ended December 31, 2015

Net cash provided by operating activities increased in 2016 compared to 2015. The increase in cash provided
by operating activities was due primarily to receipt of the federal income tax refund in August 2016 and lower
income taxes paid during 2016 compared to 2015, which both resulted from the election of bonus depreciation as

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described in Note 5 to the consolidated financial statements. Additionally, the cash received from operating revenues
increased during 2016 compared to 2015. These increases were partially offset by an increase in payments of
operating expenses and the regional cost allocation refund provided by ITCTransmission to the relevant RTOs in
October 2016 as described in Note 5 to the consolidated financial statements.

Cash Flows From Investing Activities

Year ended December 31, 2017 compared to year ended December 31, 2016

Net cash used in investing activities during the year ended December 31, 2017 was comparable to the same

period in 2016.

Year ended December 31, 2016 compared to year ended December 31, 2015

Net cash used in investing activities increased in 2016 compared to 2015. The increase in cash used in investing
activities was due primarily to the timing of payments for investments in property, plant and equipment during the
year ended December 31, 2016 compared to the same period in 2015.

Cash Flows From Financing Activities

Year ended December 31, 2017 compared to year ended December 31, 2016

Net cash provided by financing activities increased in 2017 compared to 2016. The increase in cash provided
by financing activities was due primarily to a net increase in amounts outstanding under our term loan credit
agreements compared to net repayments of term loan credit agreements in 2016 and an increase in long-term
debt issuances. These increases were partially offset by net repayments of commercial paper under our commercial
paper program and borrowing under our revolving credit agreements, an increase in payments to retire long-term
debt, an increase in dividend payments and higher net repayments associated with refundable deposits for
transmission network upgrades compared to net deposits in 2016. See Note 9 to the consolidated financial
statements on the issuances and retirement of long-term debt.

Year ended December 31, 2016 compared to year ended December 31, 2015

Net cash provided by financing activities decreased in 2016 compared to 2015. The decrease in cash provided
by financing activities was due primarily to a net decrease in amounts outstanding under our revolving and term
loan credit agreements, the settlement of share-based awards associated with the Merger, payment in connection
with an accelerated share repurchase program, a decrease in net issuances of commercial paper under our
commercial paper program and an increase in dividend payments during 2016 compared to 2015. These decreases
were partially offset by an increase in long-term debt issuances, a capital contribution from Investment Holdings,
a decrease in the repurchase and retirement of common stock, a decrease in payments to retire long-term debt
and higher net proceeds of associated with refundable deposits for transmission network upgrades. See Note 9
to the consolidated financial statements for detail on the issuances and retirements of debt.

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Contractual Obligations

The following table details our contractual obligations as of December 31, 2017:

(In millions)

Debt:

Due within

Due in

Total

1 Year

Years 2-3

Years 4-5

Due after

5 years

— $

200 $

500 $

2,050

ITC Holdings Senior Notes

ITCTransmission First Mortgage Bonds

ITCTransmission revolving credit agreement

ITCTransmission term loan credit agreement

METC Senior Secured Notes

METC revolving credit agreement

ITC Midwest First Mortgage Bonds

ITC Midwest revolving credit agreement

ITC Great Plains First Mortgage Bonds

ITC Great Plains revolving credit agreement

2,750 $
585
36

475
48

910
88

150
49

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

METC Easement Agreement

Other

Total obligations

564

528

948

167
4

329
1
8,977 $

100

—

485

—

475

—

875

—

150

—

654

445

428

747

137

—

279

—

1,159

108

205

192

421 $

720 $

1,110 $

6,726

Interest payments included above relate only to our fixed-rate long-term debt outstanding at December 31,
2017. We also expect to pay interest and commitment fees under our variable-rate revolving and term loan credit
agreements that have not been included above due to varying amounts of borrowings and interest rates under the
facilities. In 2017, we paid $9 million of interest and commitment fees under our revolving and term loan credit
agreements.

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, 2017, 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 17 to
the consolidated financial statement for more information on our operating leases and purchases obligations.

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 5 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

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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 the estimated refund related to the
Second Complaint, contingent liabilities and other long-term liabilities, due to uncertainty on the final outcome in
addition to the timing and amount of future cash flows necessary to settle these obligations. The amount of cash
flows to be paid for pension and other postretirement obligations and settle regulatory liabilities related to asset
removal costs and liabilities to refund deposits from generators for transmission network upgrades, which are
recorded in other current and long term liabilities, are not known with certainty. As a result, cash obligations for
these items are excluded from the contractual obligations table above.

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 6 to the consolidated financial statements, we had regulatory assets and liabilities of $215 million
and $802 million, respectively, as of December 31, 2017. 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 $41 million relating to intangible assets
at December 31, 2017 that are described in Note 7 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 in order 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 mechanism 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

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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 5 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
revised downward, we may be required to write down all or a portion of goodwill, which would adversely impact
earnings.

As of December 31, 2017 and 2016, consolidated goodwill totaled $950 million. We completed our annual
goodwill impairment test for our reporting units as of October 1, 2017 using a qualitative assessment and determined
that no impairment exists. There were no events subsequent to October 1, 2017, including the enactment of the
TCJA, 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.

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Refer to Note 17 to the consolidated financial statements for discussion on contingencies, including the 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 have a significant effect on the amounts reported for the health care plans as described in Note
11 to the consolidated financial statements.

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 3 to the consolidated financial statements.

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

Commodity Price Risk

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

Interest Rate Risk

Fixed Rate Debt

Based on the borrowing rates 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 $5,192 million at December 31, 2017. 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 $4,830 million at December 31, 2017. 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 credit agreements and commercial paper, at December 31, 2017. An increase in interest
rates of 10% (from 5.0% to 5.5%, for example) at December 31, 2017 would decrease the fair value of debt by
$198 million, and a decrease in interest rates of 10% at December 31, 2017 would increase the fair value of debt
by $212 million at that date.

Revolving and Term Loan Credit Agreements

At December 31, 2017, we had a consolidated total of $271 million 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. 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, 2017 would increase or decrease interest expense by $1
million, respectively, for an annual period with a constant borrowing level of $271 million.

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Commercial Paper

ITC Holdings has an ongoing commercial paper program for the issuance and sale of unsecured commercial

paper. At December 31, 2017, ITC Holdings did not have any commercial paper issued or outstanding.

Derivative Instruments and Hedging Activities

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

In November 2017, we terminated $375 million of 10-year interest rate swap contracts and $375 million of 5-
year interest rate swap contracts that managed the interest rate risk associated with the unsecured Notes issued
by ITC Holdings described in Note 9 to the consolidated financial statements. At December 31, 2017, ITC Holdings
did not have any interest rate swaps outstanding.

Credit Risk

Our credit risk is primarily with DTE Electric, Consumers Energy and IP&L, which were responsible for
approximately 22.1%, 21.3% and 25.7%, respectively, or $280 million, $269 million and $325 million, respectively,
of our consolidated billed revenues for the year ended December 31, 2017. These percentages and amounts of
total billed revenues of DTE Electric, Consumers Energy and IP&L include the collection of 2015 revenue accruals
and deferrals and exclude any amounts for the 2017 revenue accruals and deferrals that were included in our
2017 operating revenues, but will not be billed to our customers until 2019. Refer to “Item 7 Management’s
Discussion and Analysis of Financial Condition and Results of Operations — Cost-Based Formula Rates with True-
Up Mechanism” for a discussion on the difference between billed revenues and operating revenues. 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, 2017 and 2016

Consolidated Statements of Operations for the Years Ended December 31, 2017, 2016 and 2015

Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2017, 2016 and 2015

Consolidated Statements of Changes in Stockholder’s Equity for the Years Ended December 31, 2017, 2016 and
2015

Consolidated Statements of Cash Flows for the Years Ended December 31, 2017, 2016 and 2015

Notes to Consolidated Financial Statements

Schedule I — Condensed Financial Information of Registrant

Page

135

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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 extensive 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, 2017.

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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, 2017 and 2016, the related consolidated statements of
operations, comprehensive income, changes in stockholder’s equity, and cash flows for each of the three years
in the period ended December 31, 2017, 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 position of the Company as of December 31, 2017 and 2016, and the results of its
operations and its cash flows for each of the three years in the period ended December 31, 2017, 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 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 the 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 14, 2018

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,

2017

2016

119

260

108

233

Property, plant and equipment (net of accumulated depreciation and amortization of $1,675 and

$1,575, respectively)

7,309

6,698

Other assets

Goodwill

Intangible assets (net of accumulated amortization of $35 and $32, respectively)

Regulatory assets

Other

Total other assets

TOTAL ASSETS

LIABILITIES AND STOCKHOLDER’S EQUITY

Current liabilities

Accounts payable

Accrued compensation

Accrued interest

Accrued taxes

Regulatory liabilities

Refundable deposits from generators for transmission network upgrades

Debt maturing within one year

Other

Total current liabilities

Accrued pension and postretirement liabilities

Deferred income taxes

Regulatory liabilities

Refundable deposits from generators for transmission network upgrades

Other

Long-term debt

Commitments and contingent liabilities (Notes 5 and 17)

STOCKHOLDER’S EQUITY

Common stock, without par value, 235,000,000 shares authorized as of December 31, 2017, and

224,203,112 shares issued and outstanding at December 31, 2017 and 2016.

Retained earnings

Accumulated other comprehensive income

Total stockholder’s equity

950

197

1,254

8,823

183

100

562

601

619

950

247

1,292

8,223

100

129

235

633

964

249

5,001

4,355

892

1,026

1,920

892

1,007

1,901

8,223

TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY

8,823

See notes to consolidated financial statements.

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ITC HOLDINGS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In millions)
OPERATING REVENUES

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
Other expense

Total other expenses (income)
INCOME BEFORE INCOME TAXES
INCOME TAX PROVISION
NET INCOME

Year Ended December 31,
2016

2015

2017

1,211 $

1,125 $

1,045

110
123
169
103
(2)
503
708

224
(33)
(3)
5
193
515
196
319 $

114
239
158
93
(1)
603
522

211
(35)
(2)
5
179
343
97

246 $

113
145
145
82
(1)
484
561

204
(28)
(2)
3
177
384
142
242

See notes to consolidated financial statements.

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ITC HOLDINGS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In millions)
NET INCOME

OTHER COMPREHENSIVE LOSS

Derivative instruments, net of tax (Note 13)
TOTAL OTHER COMPREHENSIVE LOSS,
NET OF TAX (NOTE 13)
TOTAL COMPREHENSIVE INCOME

2017

Year Ended December 31,
2016

2015

319 $

246 $

242

—

(2)

—
319 $

(2)
244 $

(1)

(1)
241

See notes to consolidated financial statements.

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ITC HOLDINGS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN
STOCKHOLDER’S EQUITY

Common Stock

Retained
Earnings

Comprehensive Stockholder’s
Income (Loss)

Equity

Accumulated
Other

Total

(In millions)
BALANCE, DECEMBER 31, 2014
Net income

Repurchase and retirement of common stock

Dividends declared on common stock

Stock option exercises

Share-based compensation, net of forfeitures

Tax benefit for excess tax deductions of share-based compensation

Other comprehensive loss, net of tax (Note 13)

Other

BALANCE, DECEMBER 31, 2015
Net income

Repurchase and retirement of common stock

Dividends declared on common stock

Dividends to ITC Investment Holdings Inc.

Stock option exercises

Share-based compensation, net of forfeitures

Share-based compensation associated with the Merger (Note 14)

Settlement of share-based awards associated with the Merger

(Note 16)

Contribution from ITC Investment Holdings Inc. for the settlement of

share-based awards associated with the Merger (Note 16)

Tax benefit for excess tax deductions of share-based compensation

Other comprehensive loss, net of tax (Note 13)

Other

BALANCE, DECEMBER 31, 2016
Net income

Dividends to ITC Investment Holdings Inc.

BALANCE, DECEMBER 31, 2017

924

—
(137)

—

1
829

—

(9)

—

(137)

137

—

2
892

—

892

741

242

—

(108)

—

1
876

246

—

(90)
(33)
—

—

(1)

—

—
1,007

319
(300)
1,026

See notes to consolidated financial statements.

—

(1)
—

—

(2)
—

—

1,670

242
(137)

(108)

(1)
2

1,709

246

(9)

(90)
(33)
11

(138)

137

(2)
2

1,901

319
(300)
1,920

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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

Expense for the accelerated vesting of share-based awards associated with the Merger

Other

Changes in assets and liabilities, exclusive of changes shown separately:

Accounts receivable
Current regulatory assets
Income tax receivable
Other current assets
Accounts payable
Accrued compensation
Accrued taxes
Other current liabilities
Estimated refund related to return on equity complaints
Other 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 issuance (repayment) 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
Issuance of common stock
Dividends on common and restricted stock
Dividends to ITC Investment Holdings Inc.
Refundable deposits from generators for transmission network upgrades
Repayment of refundable deposits from generators for transmission network upgrades

Repurchase and retirement of common stock
Settlement of share-based awards associated with the Merger — including cost of accelerated

share-based awards

Contribution from ITC Investment Holdings Inc. for the settlement of share-based awards

associated with the Merger

Other

Net cash provided by financing activities

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

CASH AND CASH EQUIVALENTS — Beginning of period

CASH AND CASH EQUIVALENTS — End of period

See notes to consolidated financial statements.

Year Ended December 31,
2016

2015

2017

319

246

242

169

34
195
(33)
—

(17)
29
—
—
(3)
14
5
2
(113)
(4)
608

(755)
21
(10)
(744)

1,199
1,065
250
(148)
(477)
(1,178)
(200)
—
—
(300)
16
(28)
—

—

(5)
194

158

(2)
219
(35)
41

(2)
(29)
(17)
(4)
5
(11)
4
3
90
(9)
687

(750)
11
4
(735)

599
1,042
—
48
(139)
(1,028)
(361)
13
(90)
(33)
33
(10)
(9)

(137)

137

(23)
42

(6)

14
8

145
(54)
77
(28)
—

(1)
—
—
2
(7)
—
15
9
120
14
556

(701)
17
(16)
(700)

225
2,832
200
95
(175)
(2,825)
—
14
(108)
—
13
(12)
(137)

—

8
130
(14)
28

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1. GENERAL

ITC HOLDINGS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ITC Holdings Corp. and its subsidiaries are engaged in the transmission of electricity in the United States.
Through our Regulated Operating Subsidiaries, we own and operate high-voltage 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 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. We
also are pursuing transmission development projects not within our existing systems, which are also intended to
improve overall grid reliability, reduce transmission constraints and facilitate interconnections of new generating
resources, as well as enhance competitive wholesale electricity markets.

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. THE MERGER

On February 9, 2016, Fortis, FortisUS, Merger Sub and ITC Holdings entered into the Merger Agreement,
pursuant to which Merger Sub would merge with and into ITC Holdings with ITC Holdings continuing as a surviving
corporation and becoming a majority owned indirect subsidiary of Fortis. On April 20, 2016, FortisUS assigned its
rights, interest, duties and obligations under the Merger Agreement to Investment Holdings, a subsidiary of FortisUS
formed to complete the Merger. On the same date, Fortis reached a definitive agreement with a subsidiary of GIC
for that subsidiary to acquire an indirect 19.9% equity interest in ITC Holdings and debt securities to be issued by
Investment Holdings for aggregate consideration of $1.228 billion in cash upon completion of the Merger. On
October 14, 2016, ITC Holdings and Fortis completed the Merger contemplated by the Merger Agreement consistent
with the terms described above. On the same date, the common shares of ITC Holdings were delisted from the
NYSE and the common shares of Fortis were listed and began trading on the NYSE. Fortis continues to have its
shares listed on the Toronto Stock Exchange.

In the Merger, ITC Holdings shareholders received $22.57 in cash and 0.7520 Fortis common shares for each
share of common stock of ITC Holdings (the “Merger consideration”). Upon completion of the Merger, ITC Holdings
shareholders held approximately 27% of the common shares of Fortis. The per share amount of the Merger
consideration determined in accordance with the Merger Agreement and used for purposes of settling the share-
based awards was $45.72. We elected not to apply pushdown accounting to ITC Holdings or its subsidiaries in
connection with the Merger. Under the Merger Agreement, outstanding share-based awards vested as described
in Note 14.

For the year ended December 31, 2017, we expensed approximately $5 million related to the Merger for internal
labor and associated costs. For the year ended December 31, 2016, expenses related to the Merger for internal
labor and associated costs were approximately $58 million and external legal, advisory and financial services fees
were approximately $55 million. For the year ended December 31, 2016, the internal labor and associated costs
included approximately $41 million of expense that was recognized due to the accelerated vesting of the share-
based awards described in Note 14. The majority of these Merger-related costs were recorded within general and
administrative expenses. The external and internal costs related to the Merger were recorded at ITC Holdings and
have not been included as components of revenue requirement at our Regulated Operating Subsidiaries.

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3. RECENT ACCOUNTING PRONOUNCEMENTS

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.

Revenue from Contracts with Customers

In May 2014, the FASB issued authoritative guidance requiring entities to apply a new model for recognizing
revenue from contracts with customers. Subsequent updates have been issued primarily to provide implementation
guidance related to the initial guidance issued in May 2014. The guidance supersedes the current revenue
recognition guidance and requires entities to evaluate their revenue recognition arrangements using a five-step
model to determine when a customer obtains control of a transferred good or service.

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, and is considered to be in the scope of the new
guidance. The true-up mechanisms under our formula rates are considered alternative revenue programs of rate-
regulated utilities and are outside the scope of the new guidance, as they are not considered contracts with
customers. Based on our assessment of the new guidance, we do not expect the implementation of the new
standard will have a material impact on the amount and timing of revenue recognition. However, we expect to
present revenues arising from alternative revenue programs separately from revenues in the scope of the new
guidance in the statements of operations. In addition, we expect to add footnote disclosures to address the
requirements in the guidance to provide more information regarding the nature, amount, timing and uncertainty of
revenue and cash flows as well as changes in accounts receivable from customers. We are in the process of
drafting these disclosures as we continue to work towards implementation of the guidance.

The guidance is effective for annual reporting periods beginning after December 15, 2017 and may be adopted
using either (a) a full retrospective method, whereby comparative periods would be restated to present the impact
of the new standard, with the cumulative effect of applying the standard recognized as of the earliest period
presented, or (b) a modified retrospective method, under which comparative periods would not be restated and
the cumulative effect of applying the standard would be recognized at the date of initial adoption, January 1, 2018.
We expect to adopt the guidance using the modified retrospective approach. We have elected not to early adopt.

Recognition and Measurement of Financial Instruments

In January 2016, the FASB issued authoritative guidance amending the classification and measurement of
financial instruments. The guidance requires entities to carry most investments in equity securities at fair value
and recognize changes in fair value in net income, unless the investment results in consolidation or equity method
accounting. Additionally, the new guidance amends certain disclosure requirements associated with the fair value
of financial instruments. The guidance is effective for fiscal years beginning after December 15, 2017, including
interim periods within those fiscal years. Early adoption is permitted. The guidance is required to be adopted using
a modified retrospective approach, with limited exceptions. Upon adoption of the standard, we expect certain of
our investments currently accounted for as available-for-sale with changes in fair value recorded in other
comprehensive income will be required to be accounted for with changes in fair value in net income; however, we
do not expect this change in accounting will have a material impact on our consolidated financial statements. We
are continuing to assess the impact this guidance will have on our consolidated financial statements, including our
disclosures.

Accounting for Leases

In February 2016, the FASB issued authoritative guidance on accounting for leases, which impacts accounting
by lessees as well as lessors. The new guidance creates a dual approach for lessee accounting, with lease
classification determined in accordance with principles in existing lease guidance. Income statement presentation
differs depending on the lease classification; however, both types of leases result in lessees recognizing a right-
of-use asset and a lease liability, with limited exceptions. Under existing accounting guidance, operating leases
are not recorded on the balance sheet of lessees. The new guidance is effective for fiscal years beginning after

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December 15, 2018, including interim periods within those fiscal years and will be applied using a modified
retrospective approach, with possible optional practical expedients. Early adoption is permitted; however, we have
elected not to early adopt. We are currently assessing the impact this guidance will have on our consolidated
financial statements, including our disclosures.

Presentation of Restricted Cash in the Statement of Cash Flows

In November 2016, the FASB issued authoritative guidance on the presentation of restricted cash and restricted
cash equivalents within the statement of cash flows. The new guidance specifies that restricted cash and restricted
cash equivalents shall be included with cash and cash equivalents when reconciling the beginning-of-period and
end-of-period total amounts shown on the statement of cash flows. The guidance does not, however, provide a
definition of restricted cash or restricted cash equivalents. The guidance is effective for fiscal years beginning after
December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted; however, we
have elected not to early adopt. The guidance is required to be adopted using a retrospective approach to each
period presented. We are currently assessing the impact this guidance will have on our consolidated financial
statements, including our disclosures.

Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost

In March 2017, the FASB issued guidance that requires entities to disaggregate the current service cost
component of net benefit cost (i.e., net periodic pension cost and net periodic postretirement benefit cost) and
present it in the same income statement line item as other current compensation costs for employees. Entities are
required to present the other components of net benefit cost elsewhere in the income statement and outside income
from operations. The line or lines containing such other components must be appropriately described on the face
of the income statement; otherwise, disclosure of the location of such other costs in the income statement is
required. In addition, the new guidance allows capitalization of only the service cost component of net benefit cost.
The new guidance is effective for periods beginning after December 15, 2017. The changes to the presentation
of net benefit cost in the income statement are required to be adopted retrospectively (with a possible practical
expedient) while the changes regarding cost capitalization are required to be adopted prospectively. We are
currently assessing the impact this guidance will have on our financial statements, including our disclosures.

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 income
statement 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, including tabular disclosures about both (a) the total amounts reported in the income
statement for each income and expense line item that is affected by hedging and (b) the effects of hedging on
those line items. The guidance is effective for fiscal years beginning after December 15, 2018, including interim
periods within those fiscal years. Early adoption is permitted. The guidance is required to be adopted on a modified
retrospective basis to existing hedging relationships and on a prospective basis for the presentation and disclosure
requirements. We do not expect a significant impact upon adoption, but we would add the additional required
disclosures to the extent we have outstanding hedges upon adoption. We are considering early adoption in 2018.

4. 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.

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

Regulation — Our Regulated Operating Subsidiaries are subject to the regulatory jurisdiction of the FERC,
which issues orders pertaining to rates, recovery of certain costs, including the costs of transmission assets
and regulatory assets, conditions of service, accounting, financing authorization and operating-related
matters. The utility operations of our Regulated Operating Subsidiaries meet the accounting standards set
forth by the FASB for the accounting effects of certain types of regulation. These accounting standards
recognize the cost based rate setting process, which results in differences in the application of GAAP between
regulated and non-regulated businesses. These standards require the recording of regulatory assets and
liabilities for certain transactions that would have been recorded 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.

Consolidated Statements of Cash Flows — The following table presents certain supplementary cash

flows information for the years ended December 31, 2017, 2016 and 2015:

(In millions)
Supplementary cash flows information:

Interest paid (net of interest capitalized) (a)
Income taxes paid (b)

Supplementary non-cash investing and financing activities:

Additions to property, plant and equipment and other long-lived

assets (c)

Allowance for equity funds used during construction

____________________________

Year Ended December 31,
2016

2017

2015

213 $
—

190 $

87 $
33

93 $
35

191
56

110
28

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

ROE complaints. See Note 17 for information on the ROE complaints.

(b) Amount for the year ended December 31, 2016 does not include the income tax refund of $128 million
received from the IRS in August 2016, which resulted from the election of bonus depreciation as described
in Note 5.

(c) 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,
2017, 2016 or 2015, respectively, but have been or will be 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 statement of operations.
Cash retained as a result of those excess tax benefits is presented in the statement of cash flows as cash
inflows from operating activities.

Accounts Receivable — We recognize losses for uncollectible accounts based on specific identification

of any such items. As of December 31, 2017 and 2016, 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 $160 million, $149 million and $136 million for 2017, 2016 and 2015, 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

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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
operations was 2.0%, 2.0% and 2.1% for 2017, 2016 and 2015, respectively. 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 of $9 million, $9 million and $7 million was a reduction to interest expense for 2017, 2016 and
2015, respectively.

For acquisitions of property, plant and equipment greater than the net book value (other than asset
acquisitions accounted for under the purchase method of accounting that result in goodwill), the acquisition
premium is recorded to property, plant and equipment and amortized over the estimated remaining useful
lives of the assets using the straight-line method for financial reporting purposes and accelerated methods
for income tax reporting purposes.

Property, plant and equipment includes capital equipment 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
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 Regulatory
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.

Available-For-Sale Securities — We have certain investments in debt and equity securities that are
classified as available-for-sale securities. These investments currently fund our two supplemental
nonqualified, noncontributory, retirement benefit plans for selected management employees as described
in Note 11. Unrealized gains recorded for the investments are reported, net of tax, as a component of other
comprehensive income (loss). Any unrealized losses (where cost exceeds fair market value) on the
investments will also be reported, net of tax, as a component of other comprehensive income (loss), unless
the unrealized loss is other than temporary, in which case it would be recorded as an investment loss in the
consolidated statements of operations.

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 operations.

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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, 2017 and
determined that no impairment exists. There were no events subsequent to October 1, 2017, including the
enactment of the TCJA, 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 7 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 $4 million to interest expense for the amortization of
deferred financing fees and debt discounts during each of the years ended December 31, 2017, 2016 and
2015.

Asset Retirement Obligations — A conditional asset retirement obligation is a legal obligation to perform
an asset retirement activity in which the timing and/or method of settlement are conditional on a future event
that may or may not be within our control. We have identified conditional asset retirement obligations primarily
associated with the removal of equipment containing PCBs and asbestos. We record a liability at fair value
for a legal asset retirement obligation in the period in which it is incurred. When a new legal obligation is
recorded, we capitalize the costs of the liability by increasing the carrying amount of the related long-lived
asset. We accrete the liability to its present value each period and depreciate the capitalized cost over the
useful life of the related asset. At the end of the asset’s useful life, we settle the 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 2017. Our
asset retirement obligations as of December 31, 2017 and 2016 of $6 million and $5 million, respectively,
are included in other liabilities.

Financial Instruments — For derivative instruments that have been designated and qualify as cash flow
hedges of the exposure to variability in expected future cash flows, the 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
statement of operations when the underlying hedged transaction affects net income. Any hedge
ineffectiveness is recognized in net income immediately at the time the gain or loss on the derivative
instruments is calculated. Refer to Note 9 for additional discussion regarding derivative instruments. Cash
flows related to derivative instruments that are designated in hedging relationships are generally classified
on the statement of cash flows in the same category as the cash flows from the associated hedged item.

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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. 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.

Revenues — Revenues from the transmission of electricity are recognized as services are provided based
on 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.

Share-Based Payment and Employee Share Purchase Plan — We have an Omnibus Plan, pursuant to
which we may grant long term incentive awards of performance-based units and service-based units. 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 14 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,
any gain or loss recognized for the effective portion of our interest rate swaps and any unrealized gain or
loss associated with our available-for-sale securities.

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, 2017, we have not recognized any uncertain income tax positions.

We file income tax returns with the IRS and with various state and city jurisdictions. We are no longer
subject to U.S. federal tax examinations for tax years 2012 and earlier. State and city jurisdictions that remain
subject to examination range from tax years 2013 to 2016. 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 operations.

Refer to Notes 6 and 10 for additional discussion on income taxes and tax reform.

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5. REGULATORY MATTERS

Cost-Based Formula Rates with True-Up Mechanism

The transmission revenue requirements at our Regulated Operating Subsidiaries are set annually, using a
FERC-approved formula that is used to calculate rates (“formula rates”), and remain in effect for a one-year period.
By updating the inputs to the formula and resulting rates on an annual basis, the revenues at our Regulated
Operating Subsidiaries reflect changing operational data and financial performance, including the amount of
network load on their transmission systems (for our MISO Regulated Operating Subsidiaries), operating expenses
and additions to property, plant and equipment when placed in service, among other items. The formula used to
derive the rates does not require further action or FERC filings each year, although the formula inputs remain
subject to legal challenge at the FERC. Our Regulated Operating Subsidiaries will continue to use the formula to
calculate their respective annual revenue requirements unless the FERC determines the resulting rates to be
unjust and unreasonable and another mechanism is determined by the FERC to be just and reasonable. See “Rate
of Return on Equity Complaints” in Note 17 for detail on ROE matters for our MISO Regulated Operating
Subsidiaries.

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, 2017:

(In millions)

Net regulatory liability as of December 31, 2016

Net collection of 2015 revenue deferrals and accruals, including accrued interest

Net revenue deferral for the year ended December 31, 2017

Net accrued interest payable for the year ended December 31, 2017

Net regulatory liability as of December 31, 2017

Total

(1)

(15)

(17)

(2)

(35)

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
at December 31, 2017 and 2016 as follows:

(In millions)
Current regulatory assets

Non-current regulatory assets

Current regulatory liabilities
Non-current regulatory liabilities
Net regulatory liability as of December 31, 2017

ITCTransmission Regional Cost Allocation Refund

2017

2016

18 $
11
(38)
(26)
(35) $

24
16
(9)
(32)
(1)

In October 2010, MISO and ITCTransmission made a filing with the FERC under Section 205 of the FPA to
revise the MISO tariff to establish a methodology to allocate and recover costs of ITCTransmission’s PARs among
MISO and other FERC-approved RTOs — the New York Independent System Operator and PJM Interconnection
(“Other RTOs”). In December 2010, the FERC accepted the proposed revisions, subject to refund, while setting
them for hearing and settlement procedures. On September 22, 2016, the FERC issued an order largely affirming
the presiding administrative law judge’s initial decision issued in December 2012, which stated, among other things,
that MISO and ITCTransmission failed to show that the Other RTOs will benefit from the operation of

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ITCTransmission’s PARs. The FERC order required ITCTransmission to provide refunds within 30 days for excess
amounts collected from customers of the Other RTOs. The refunds, including interest, were provided to the Other
RTOs in October 2016. On December 6, 2016, ITCTransmission made a filing with the FERC, under Section 205
of the FPA, requesting to recover the amount refunded to the Other RTOs (“regional cost allocation recovery”) in
network rates during the next calendar year, beginning January 1, 2017. On January 30, 2017, the FERC issued
an order approving collection of the regional cost allocation recovery in 2017. ITCTransmission recorded $29 million
for the regional cost allocation recovery, including interest, in current regulatory assets on the consolidated
statement of financial position as of December 31, 2016. As a result of the FERC order, ITCTransmission collected
the amounts refunded, plus interest, from network customers in 2017. The regulatory asset was amortized in 2017
and no balance was recorded in regulatory assets related to regional cost allocation recovery as of December 31,
2017.

MISO Funding Policy for Generator Interconnections

On June 18, 2015, the FERC issued an order initiating a proceeding, pursuant to Section 206 of the FPA, to
examine MISO’s funding policy for generator interconnections, which allowed a TO to unilaterally elect to fund
network upgrades and recover such costs from the interconnection customer. In this order, the FERC found that
the MISO funding policy may be unduly discriminatory, and suggested the MISO funding policy be revised to
require mutual agreement between the interconnection customer and TO for the TO to utilize the election to fund
network upgrades. In the absence of such mutual agreement, the facilities would be funded solely by the
interconnection customer. On January 8, 2016, MISO made a compliance filing to revise its funding policy to adopt
the FERC suggestion to require mutual agreement between the customer and TO, with an effective date of June
24, 2015. Our MISO Regulated Operating Subsidiaries, along with another MISO TO, have appealed the FERC’s
orders on this issue. On January 26, 2018, the U.S. Court of Appeals for the District of Columbia Circuit issued
an opinion which concluded that evidence does not support the FERC’s position as applied to TOs without affiliated
generation assets. In addition, the opinion noted that the FERC did not adequately respond to the argument that
an involuntary generator funding requirement would compel a TO to construct, own, and operate facilities without
compensatory network upgrade charges, which would force the TO to accept additional risk without corresponding
return. As a result, the court vacated the orders and remanded this case to the FERC. We do not expect the
resolution of this proceeding to have a material impact on our consolidated results of operations, cash flows or
financial condition.

MISO Formula Rate Template Modifications Filing

On October 30, 2015, our MISO Regulated Operating Subsidiaries requested modifications, pursuant to Section
205 of the FPA, to certain aspects of their respective FERC-approved formula rate templates which included,
among other things, changes to ensure that various income tax items are computed correctly for purposes of
determining their revenue requirements. Our MISO Regulated Operating Subsidiaries requested an effective date
of January 1, 2016 for the proposed template changes. On December 30, 2015, the FERC conditionally accepted
the formula rate template modifications and required a further compliance filing, which was made on February 8,
2016. On April 14, 2016, the FERC issued an order accepting the February 8, 2016 compliance filing, effective
January 1, 2016. The formula rate templates, prior to any proposed modifications, include certain deferred income
taxes on contributions in aid of construction in rate base that resulted in recovery of excess amounts from customers.
As of December 31, 2016, our MISO Regulated Operating Subsidiaries had recorded an aggregate refund liability
of $2 million reported in current regulatory liabilities. During the year ended December 31, 2017, we provided the
remaining refunds with interest.

Challenge Regarding Bonus Depreciation

On December 18, 2015, IP&L filed a formal challenge (“IP&L challenge”) with the FERC against ITC Midwest
on certain inputs to ITC Midwest’s formula rates. The IP&L challenge alleged that ITC Midwest has unreasonably
and imprudently opted out of using bonus depreciation in the calculation of its federal income tax expense and
thereby unduly increased the transmission charges for transmission service to customers. On March 11, 2016,
the FERC granted the IP&L challenge in part by requiring ITC Midwest to recalculate its revenue requirements,
effective January 1, 2015, to simulate the election of bonus depreciation for 2015. On June 8, 2016, the FERC
denied ITC Midwest’s request for rehearing of the March 11, 2016 order. On August 3, 2016, ITC Midwest filed a
petition for review of the FERC’s March 11, 2016 and June 8, 2016 orders in the United States Court of Appeals,
District of Columbia Circuit. On September 8, 2016, ITC Midwest filed a motion to defer the petition pending the

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issuance of a private letter ruling from the IRS. Following ITC Midwest’s receipt of a private letter ruling, which
confirmed that ITC Midwest would not violate the IRS rules related to ratemaking by following the FERC order to
calculate rates to simulate the election of bonus depreciation for the historical 2015 year, and after consideration
of other relevant factors, ITC Midwest moved the court for leave to withdraw our appeal on March 15, 2017, which
was granted by the Court on March 20, 2017, and this matter is now concluded. We intend to elect bonus
depreciation for 2017 as permissible under the TCJA.

Rate of Return on Equity Complaints

See “Rate of Return on Equity Complaints” in Note 17 for a discussion of the complaints.

6. REGULATORY ASSETS AND LIABILITIES

Regulatory Assets

The following table summarizes the regulatory asset balances at December 31, 2017 and 2016:

(In millions)
Regulatory Assets:

Current:

2017

2016

Revenue accruals (including accrued interest of less than $1 as of December 31,

2017 and 2016) (a)

18 $

ITCTransmission regional cost allocation recovery (including accrued interest of

less than $1 as of December 31, 2016) (b)

Total current

Non-current:

Revenue accruals (including accrued interest of less than $1 as of December 31,

2017 and 2016) (a)

ITCTransmission ADIT deferral (net of accumulated amortization of $45 and $42

as of December 31, 2017 and 2016, respectively)

METC ADIT deferral (net of accumulated amortization of $26 and $24 as of

December 31, 2017 and 2016, respectively)

METC regulatory deferrals (net of accumulated amortization of $9 and $8 as of

December 31, 2017 and 2016, respectively)

Income taxes recoverable related to AFUDC equity (c)
ITC Great Plains start-up, development and pre-construction (net of accumulated
amortization of $3 and $2 as of December 31, 2017 and 2016, respectively)
Pensions and postretirement
Income taxes recoverable related to implementation of the Michigan Corporate

Income Tax and other state excess deficient taxes (c)

—

80
10

30
7

Accrued asset removal costs

Total non-current

Total

____________________________

19
197

215 $

124
11

25
9

16
247

300

(a) Refer to discussion of revenue accruals in Note 5 under “Cost-Based Formula Rates with True-Up Mechanism.”
Our Regulated Operating Subsidiaries do not earn a return on the balance of these regulatory assets, but do
accrue interest carrying costs, which are subject to rate recovery along with the principal amount of the revenue
accrual.

(b) Refer to discussion of ITCTransmission regional cost allocation recovery in Note 5 under “ITCTransmission

Regional Cost Allocation Refund.”

(c) In 2017, income taxes recoverable related to AFUDC equity and income taxes recoverable related to
implementation of the Michigan Corporate Income Tax and other state excess deficient taxes decreased by
$63 million and $2 million, respectively, as a result of the implementation of the TCJA. Refer to discussion of
the TCJA in Note 10.

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ITCTransmission ADIT Deferral

The carrying amount of the ITC Transmission 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 2017, 2016 and 2015, which is included in depreciation and
amortization 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. 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 base. METC recorded amortization expense of $2
million annually during 2017, 2016 and 2015, which is included in depreciation and amortization 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, 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 2017, 2016 and 2015, which is included in depreciation and
amortization 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 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.

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

In May 2011, the Michigan Business Tax was repealed and replaced with the Michigan Corporate Income Tax,
effective January 1, 2012. 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 addition
to the traditional income tax, the Michigan Business Tax had also included a modified gross receipts tax that allowed
for deductions and credits for certain activities, none of which are part of the Michigan Corporate Income Tax. The
change in Michigan tax law required us in 2011 to remove deferred income tax balances recognized under the
Michigan Business Tax and 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

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 reduces this regulatory
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.

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Regulatory Liabilities

The following table summarizes the regulatory liability balances at December 31, 2017 and 2016:

(In millions)
Regulatory Liabilities:

Current:

2017

2016

Revenue deferrals (including accrued interest of $2 and less than $1 as of

38 $

December 31, 2017 and 2016, respectively) (a)

Refund related to the formula rate template modifications (including accrued

interest of $1 as of December 31, 2016) (b)

Estimated refund related to return on equity complaints (including accrued interest

of $11 and $9 as of December 31, 2017 and 2016, respectively.) (c)

Total current

Non-current:

Revenue deferrals (including accrued interest of $1 and $1 as of December 31,

2017 and 2016, respectively) (a)

Accrued asset removal costs
Estimated refund related to return on equity complaint (including accrued interest

of $6 as of December 31, 2016) (c)

Excess state income tax deductions (d)
Income taxes refundable related to implementation of the TCJA (d)

Total non-current

Total

____________________________

—

145

183

72
—

7
514
619

802 $

118

129

68
140

9
—
249

378

(a) Refer to discussion of revenue deferrals in Note 5 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 in Note 5 under “MISO Formula Rate Template Modifications Filing.”

(d) In 2017, net non-current regulatory liabilities of $512 million were recorded related to the implementation of
the TCJA. A regulatory liability of $514 million was recorded for income taxes refundable related to the
implementation, while the regulatory liability for excess state income tax deductions was reduced by $2 million.
Refer to discussion of the TCJA in Note 10.

Accrued Asset Removal Costs

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.

Income Taxes Refundable Related to Implementation of the TCJA

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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 the average rate assumption method (ARAM) for the determination of the timing of the return of the
excess deferred taxes to customers associated with public utility property. 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 the timing of the settlement with customers has not yet been determined. This net
regulatory liability is included within deferred taxes for rate-making purposes when determining rate base.

7. GOODWILL AND INTANGIBLE ASSETS

Goodwill

At December 31, 2017 and 2016, 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
the METC ADIT Deferral as described in Note 6. The carrying amounts of the intangible asset for the METC
Regulatory Deferrals and the METC ADIT Deferral were $18 million and $8 million, respectively, as of December 31,
2017, and $20 million and $8 million, respectively, as of December 31, 2016. 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 and $15 million (net of accumulated amortization of $2 million
and $1 million, respectively) as of December 31, 2017 and 2016, respectively. The amortization period for these
intangible assets is 50 years.

We recorded $1 million of other intangible assets as of December 31, 2017. There were no other intangible

assets recorded as of December 31, 2016.

During each of the years ended December 31, 2017, 2016 and 2015, we recognized $3 million of amortization
expense of our intangible assets. We expect the annual amortization of our intangible assets that have been
recorded as of December 31, 2017 to be as follows:

(In millions)
2018
2019
2020
2021
2022
2023 and thereafter

Total

3
3
3
3
3
25
40

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8. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment — net consisted of the following at December 31, 2017 and 2016:

(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

2017

2016

8,334 $
546
74
16
14
8,984
(1,675)
7,309 $

7,715
455
74
15
14
8,273
(1,575)
6,698

Additions to property, plant and equipment in service and construction work in progress during 2017 and 2016
were due primarily for 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 Multi-Value Projects.

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9. DEBT

The following amounts were outstanding at December 31, 2017 and 2016:

(In millions)

2017

2016

ITC Holdings 6.23% Senior Notes, Series B, due September 20, 2017 (a)

— $

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

ITC Holdings 6.05% Senior Notes, due January 31, 2018 (b)

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

ITC Holdings Commercial Paper Program (a)

ITCTransmission 6.125% First Mortgage Bonds, Series C, due March 31, 2036

ITCTransmission 5.75% First Mortgage Bonds, Series D, due April 1, 2018 (a)

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 Term Loan Credit Agreement, due March 23, 2019

ITCTransmission Revolving Credit Agreement, due October 21, 2022 (c)

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

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

ITC Midwest 7.12% First Mortgage Bonds, Series B, due December 22, 2017 (a)

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

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

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

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

Total principal

Unamortized deferred financing fees and discount

Total debt

____________________________

200

—

200

250

400

300

400

500

—

100

285

100

150

200

175

—

100

225

200

150

200

385

200

250

400

300

400

—

145

100

285

100

—

150

200

175

100

225

—

127

150

5,141

(40)

4,624

(34)

5,101

4,590

(a) As of December 31, 2017 and 2016, there was $100 million and $235 million, respectively, of debt included
within debt maturing within one year that is classified as a current liability in the consolidated statements of
financial position.

(b) On December 14, 2017, we redeemed the full $385 million balance of ITC Holdings Senior Notes due January
31, 2018. We recorded a $2 million loss on extinguishment of the debt at the time of the redemption, which is
included in Interest expense - net in the consolidated statements of operations.

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(c) On October 23, 2017, ITC Holdings, ITCTransmission, METC, ITC Midwest and ITC Great Plains entered into
new, unsecured, unguaranteed revolving credit agreements, which replaced the previous revolving credit and
extended the maturity date of the revolving credit agreements from March 2019 to October 2022.

The annual maturities of debt as of December 31, 2017 are as follows:

(In millions)
2018
2019
2020
2021
2022
2023 and thereafter

Total

ITC Holdings

Senior Unsecured Notes

100
50
235
—
721
4,035
5,141

On November 14, 2017, ITC Holdings completed the private offering of $500 million aggregate principal amount
of unsecured 2.70% Senior Notes, due November 15, 2022, and $500 million aggregate principal amount of
unsecured 3.35% Senior Notes, due November 15, 2027, (collectively, the “2017 Senior Notes”). The 2017 Senior
Notes are redeemable prior to the due date, in whole or in part and at the option of ITC Holdings, by paying an
applicable make whole premium. The net proceeds from this offering were used to redeem in full $385 million
aggregate principal amount of ITC Holdings 6.05% Senior Notes due January 31, 2018, and to pay the associated
call premiums, to repay the amount outstanding under ITC Holdings’ 2017 term loan credit agreement, to repay
$7 million under ITC Holdings’ revolving credit agreement, and to repay $352 million under ITC Holdings’ commercial
paper program, with remaining proceeds used for general corporate purposes. The 2017 Senior Notes were issued
under ITC Holdings’ indenture, dated April 18, 2013.

In connection with the offering of the 2017 Senior Notes, ITC Holdings also entered into a registration rights
agreement with the representatives of the initial purchasers named therein. Pursuant to this registration rights
agreement, ITC Holdings agreed to use its commercially reasonable efforts to file with the SEC and cause to
become effective a registration statement with respect to a registered exchange offer to exchange each series of
Senior Notes issued in the offering for an issue of notes having terms substantially identical to the applicable series
of Senior Notes (except for provisions relating to the transfer restrictions and payment of additional interest) as
part of an offer to exchange such registered notes for the notes (the “Exchange Offer”). ITC Holdings also agreed
to file a shelf registration statement to cover resales of the notes under certain circumstances. ITC Holdings is
expected to have the registration statement relating to the Exchange Offer declared effective by the SEC on or
prior to 365 days after the date of issuance of the 2017 Senior Notes, or, to the extent a shelf registration statement
is required to be filed, to have such shelf registration statement declared effective by the SEC on or prior to the
90th day following the date such shelf registration statement was filed. If this obligation is not satisfied, the annual
interest rate on the notes will increase by 25 basis points for the first 90 days commencing on the day following
the registration default, and by an additional 25 basis points per annum with respect to each subsequent 90-day
period, up to a maximum additional rate of 100 basis points per annum thereafter until the earliest of the Exchange
Offer being completed or the shelf registration statement, if required, becoming effective.

On July 5, 2016, ITC Holdings issued $400 million aggregate principal amount of unsecured 3.25% Notes, due
June 30, 2026. The proceeds from the issuance were used to repay the $161 million outstanding under ITC
Holdings’ term loan credit agreement and for general corporate purposes, primarily the repayment of indebtedness
outstanding under ITC Holdings’ commercial paper program. These Notes were issued under ITC Holdings’
indenture, dated April 18, 2013.

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, 2017,
ITC Holdings did not have any commercial paper issued or outstanding. The proceeds from issuances under the
program during the year ended December 31, 2017 were used to repay and retire the $50 million of ITC Holdings’

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6.23% Senior Notes, due September 20, 2017, and for general corporate purposes, including the repayment of
borrowings under ITC Holdings’ revolving credit agreement. ITC repaid borrowings under the commercial paper
program of $352 million in November 2017 with proceeds from the ITC Holdings 2017 Senior Notes issued on
November 14, 2017.

Term Loan Credit Agreement

On March 23, 2017, ITC Holdings entered into an unsecured, unguaranteed term loan credit agreement due
March 24, 2018, under which ITC Holdings borrowed $200 million. The proceeds were used for general corporate
purposes, including the repayment of borrowings under ITC Holdings’ revolving credit agreement and commercial
paper program. This borrowing was repaid in full in November 2017 from the proceeds of the ITC Holdings Senior
Notes issued on November 14, 2017. The weighted-average interest rate throughout the life of the loan was 2.06%.

METC

On April 26, 2016, METC issued $200 million of 3.90% Senior Secured Notes, due April 26, 2046. The proceeds
were used to repay the $200 million borrowed under METC’s term loan credit agreement discussed below. The
METC Senior Secured Notes were issued under its first mortgage indenture and secured by a first mortgage lien
on substantially all of its real property and tangible personal property.

ITC Midwest

On April 18, 2017, ITC Midwest issued $200 million aggregate principal amount of 4.16% First Mortgage Bonds,
Series H, due April 18, 2047. The proceeds were used for general corporate purposes, including the repayment
of borrowings under the ITC Midwest revolving credit agreement. ITC Midwest’s First Mortgage Bonds were issued
under its First Mortgage and Deed of Trust and secured by a first mortgage lien on substantially all of its real
property and tangible personal property.

ITCTransmission

On March 23, 2017, ITCTransmission entered into an unsecured, unguaranteed term loan credit agreement
due March 23, 2019, under which ITCTransmission borrowed $50 million. The proceeds were used for general
corporate purposes, including the repayment of borrowings under ITCTransmission’s revolving credit agreement.
The weighted-average interest rate on the borrowing outstanding under this agreement was 2.03% at December 31,
2017.

Derivative Instruments and Hedging Activities

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

In November 2017, we terminated $375 million of 5-year interest rate swap contracts and $375 million of 10-
year interest rate swap contracts that managed the interest rate risk associated with the 2017 Senior Notes issued
by ITC Holdings. A summary of the terminated interest rate swaps is provided below:

Interest Rate Swaps
(In millions, except percentages)
5-year interest rate swaps

10-year interest rate swaps

Total

Amount

375

750

Weighted Average
Fixed Rate of
Interest Rate Swaps
1.85%

Comparable
Reference Rate
of Notes

Gain on
Derivatives

Settlement
Date

2.06% $

4 November 2017

2.22%

2.31%

3 November 2017

The interest rate swaps qualified for cash flow hedge accounting treatment and the pre-tax gain of $7 million
was recognized in November 2017 for the effective portion of the hedges and recorded net of tax in AOCI. This
amount is being amortized as a component of interest expense over the life of the related debt. At December 31,
2017, ITC Holdings did not have any interest rate swaps outstanding.

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Revolving Credit Agreements

On October 23, 2017, ITC Holdings, ITCTransmission, METC, ITC Midwest and ITC Great Plains entered into
new, unsecured, unguaranteed revolving credit agreements, which replaced the previous revolving credit
agreements then in effect. The new revolving credit agreements (a) extended the maturity date of the revolving
credit agreements from March 2019 to October 2022 and (b) reduced the total available capacity for the revolving
credit agreements for ITC Great Plains and ITC Midwest by $75 million and $25 million, respectively. At
December 31, 2017, ITC Holdings and certain of its Regulated Operating Subsidiaries had the following unsecured
revolving credit facilities available:

(In millions, except percentages)

Total
Available
Capacity

Outstanding
Balance (a)

Unused
Capacity

ITC Holdings
ITCTransmission
METC
ITC Midwest
ITC Great Plains

Total

400 $
100
100
225
75

900 $

— $
36
48
88
49

221 $

400 (c)

64
52
137
26
679

____________________________

(a) Included within long-term debt.

Weighted Average
Interest Rate on
Outstanding
Balance
—%
2.5%
2.5%
2.5%
2.5%

(d)

(e)

(e)
(e)

Commitment
Fee Rate (b)
0.175%
0.10%
0.10%
0.10%
0.10%

(b) Calculation based on the average daily unused commitments, subject to adjustment based on the borrower’s

credit rating.

(c) 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. At
December 31, 2017 ITC Holdings did not have any commercial paper issued or outstanding.

(d) Loan bears interest at a rate equal to LIBOR plus an applicable margin of 1.25% or at a base rate, which is
defined as the higher of the prime rate, 0.50% above the federal funds rate or 1.00% above the one month
LIBOR, plus an applicable margin of 0.25%, subject to adjustments based on ITC Holdings’ credit rating.

(e) Loans bear interest at a rate equal to LIBOR plus an applicable margin of 1.00% or at a base rate, which is
defined as the higher of the prime rate, 0.50% above the federal funds rate or 1.00% above the one month
LIBOR, subject to adjustments based on the borrower’s credit rating.

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, selling or otherwise disposing of all or substantially all of our assets and paying dividends.
In addition, the covenants require us to meet certain financial ratios, such as maintaining certain net debt to
capitalization ratios and certain funds from operations to net debt levels. As of December 31, 2017, we were not
in violation of any debt covenant.

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10.

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 35% statutory rate
State income taxes (net of federal benefit) (a)
AFUDC equity
Revaluation of deferred federal income taxes (b)
Excess tax deductions for share-based compensation (c)
Other — net (d)

Total income tax provision

____________________________

2017

2016

2015

180 $

16
(10)
8
—
2
196 $

120 $
3
(11)
—
(23)
8

97 $

134
14
(8)
—
—
2
142

(a) 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.

(b) 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.

adopting the new accounting guidance associated with share-based payments.

(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 expense (benefit) (a)
Deferred income tax expense (b)(c)(d)

Total income tax provision

____________________________

2017

2016

2015

1 $

195
196 $

(122) $
219

97 $

65
77
142

(a) Amount for the year ended December 31, 2016 primarily relates to the cash benefit that resulted from the

election of bonus depreciation as described in Note 5.

(b) 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.

(c) During the fourth quarter of 2016, we recognized total income tax benefits of $27 million for excess tax
deductions for the year ended December 31, 2016 as a result of adopting the new accounting guidance
associated with share-based payments.

(d) Amount for the year ended December 31, 2016 includes utilization of $126 million of net operating losses,

primarily resulting from the election of bonus depreciation as described in Note 5.

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.

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 revaluation of the deferred tax assets and federal
income tax net operating losses at ITC Holdings has resulted in additional income tax expense in the fourth quarter
of 2017 of $5 million. For additional information on the impacts of tax reform, see Note 6.

Due to the complexities involved in accounting for the enactment of the TCJA, the SEC staff issued Staff
Accounting Bulletin No. 118 (“SAB 118”) to address the application of U.S. GAAP in situations when a registrant

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does not have the necessary information available, prepared, or analyzed (including computations) in reasonable
detail to complete the accounting for certain income tax effects of the TCJA. Accordingly, based on information
available, we have recognized provisional tax impacts in its consolidated financial statements for the year ended
December 31, 2017. The additional estimated income tax expense recorded as a result of the TCJA represents
our best estimate based on interpretation of the TCJA. The ultimate impact may differ from these provisional
amounts, possibly materially, due to, among other things, additional analysis, changes in interpretations and
assumptions we have made, additional regulatory guidance that may be issued, and actions we may take as a
result of the TCJA.

We are still in the process of evaluating the bonus depreciation carve-out for regulated utilities and we anticipate
further clarification from the IRS, including tax depreciation elections for assets placed in service after September
27, 2017. We have recorded an estimated provision for bonus depreciation for our fixed assets placed in service
between September 27, 2017 and December 31, 2017, which impacts our deferred tax liability for property, plant
and equipment and deferred tax asset for federal income tax NOLs and other credits.

We will continue to analyze the effects of the TCJA on our consolidated financial statements and operations.
Additional impacts from the enactment of the TCJA will be recorded as they are identified during the measurement
period as provided for in SAB 118.

Deferred income tax assets (liabilities) consisted of the following at December 31:

(In millions)
Property, plant and equipment
Federal income tax NOLs and other credits
METC regulatory deferral (a)
Acquisition adjustments — ADIT deferrals (a)
Goodwill
ITCTransmission regional cost allocation recovery (b)
Refund liabilities (a)
Regulatory liability gross up - TCJA
Pension and postretirement liabilities
State income tax NOLs (net of federal benefit) (c)
True-up adjustment principal & interest
Other — net

Net deferred tax liabilities (d)

Gross deferred income tax liabilities
Gross deferred income tax assets

Net deferred tax liabilities

____________________________

(a) Described in Note 6.

2017

2016

(798) $
84
(6)
(10)
(120)
—
38
139
16
50
9
(3)
(601) $
(952) $
351
(601) $

(1,026)
140
(11)
(15)
(163)
(11)
56
—
23
47
1
(5)
(964)
(1,252)
288
(964)

$
$

(b) Described in Note 5 under “ITC Transmission Regional Cost Allocation Refund”.

(c) During the fourth quarter of 2016, we recorded a deferred tax asset of $9 million for state income tax net
operating losses, related to excess tax benefits generated in periods prior to 2016 that had not been previously
recognized in the consolidated statements of financial position, upon adoption of the accounting guidance
associated with share-based payments.

(d) During the fourth quarter of 2017, we recorded a reduction in the net deferred tax liabilities of $572 million and
income tax expense of $5 million related to the revaluation of deferred taxes as a result of the reduction in the
U.S. federal corporate income rate from 35% to 21%. The revaluation was offset by a regulatory liability of
approximately $512 million and a reduction in regulatory assets of $65 million.

We have federal income tax NOLs and capital losses as of December 31, 2017. We expect to use our NOLs
prior to their expirations starting in 2036. However, during the fourth quarter of 2017, we established a $1 million
valuation allowance for our federal capital loss we expect to not be utilized before its expiration at the end of 2018.

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We also have state income tax NOLs as of December 31, 2017, all of which we expect to use prior to their expiration
starting in 2022.

11. RETIREMENT BENEFITS AND ASSETS HELD IN TRUST

Pension 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 to contribute amounts necessary to meet the minimum funding requirements of the Employee
Retirement Income Security Act of 1974, plus additional amounts as we determine appropriate. We made contributions
of $4 million, $3 million and $4 million to the retirement plan in 2017, 2016 and 2015, respectively. We expect to
contribute $4 million to the retirement plan in 2018.

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 $53 million and $42 million at December 31,
2017 and 2016, respectively, are not included in the plan asset amounts presented below, but are included in other
assets on our consolidated statements of financial position. For the years ended December 31, 2017, 2016 and
2015, we contributed $14 million, $5 million and $9 million, respectively, to these supplemental benefit plans.

Our investments held for the supplemental benefit plans are classified as available-for-sale securities and the
life-to-date net unrealized loss of less than $1 million as of December 31, 2017 and December 31, 2016 was recognized
in AOCI.

The plan assets of the retirement plan consisted of the following assets by category:

Asset Category
Fixed income securities
Equity securities

Total

2017

50.2%
49.8%
100.0%

2016

50.3%
49.7%
100.0%

Net periodic benefit cost for the pension plans during 2017, 2016 and 2015 was as follows by component:

(In millions)
Service cost
Interest cost
Expected return on plan assets
Amortization of unrecognized loss

Net pension cost

2017

2016

2015

6 $
4
(4)
1
7 $

6 $
4
(4)
4

10 $

6
4
(3)
4
11

Prior to 2016, we measured service and interest costs for all pension plans utilizing a single weighted-average
discount rate derived from the yield curve used to measure the plan obligations. Beginning in 2016, we adopted a
spot rate approach for measuring service and interest costs for all our pension plans whereby specific spot rates
along the yield curve used to determine the benefit obligations are applied to the relevant projected cash flows. We
believe the new approach provides a more precise measurement of our service and interest costs; therefore, we
have accounted for this change prospectively as a change in accounting estimate. This change does not affect the
measurement of our total benefit obligation and it did not have a material impact on 2016 net pension cost.

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The following table reconciles the obligations, assets and funded status of the pension plans as well as the
presentation of the funded status of the pension plans in the consolidated statements of financial position as of
December 31, 2017 and 2016:

(In millions)
Change in Benefit Obligation:

Beginning projected benefit obligation
Service cost
Interest cost
Actuarial net 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 liabilities
Other non-current assets
Other current liabilities

Total
Unrecognized Amounts in Non-current Regulatory Assets:

Net actuarial loss

Total

2017

2016

$
$

(116)
(6)
(4)
(7)
6
(127)

64
9
4
(2)
75
(52)

(67)
(56)
(123)

(54)
6
(4)
(52)

26
26

$
$

(97)
(6)
(4)
(11)
2
(116)

58
5
3
(2)
64
(52)

(56)
(55)
(111)

(52)
4
(4)
(52)

25
25

Actuarial assumptions used to determine the benefit obligation for the pension plans at December 31, 2017, 2016

and 2015 are as follows:

Weighted average discount rate (a)
Annual rate of salary increases

____________________________

2017
3.57%

4.00%

2016
4.00%

4.00%

2015
4.26%

4.00%

(a) The 2015 discount rate assumption has been presented to conform to weighted average presentation.

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Actuarial assumptions used to determine the benefit cost for the pension plans for the years ended December 31,

2017, 2016 and 2015 are as follows:

Weighted average discount rate — service cost (a)
Weighted average discount rate — interest cost (a)
Annual rate of salary increases
Expected long-term rate of return on plan assets

____________________________

2017
4.20%

3.45%

4.00%

6.20%

2016
4.46%

3.62%

4.00%

6.40%

2015
3.95%

3.95%

4.00%

6.70%

(a) The 2015 discount rate assumptions have been presented to conform to weighted average presentation.

At December 31, 2017, the projected benefit payments for the pension plans calculated using the same

assumptions as those used to calculate the benefit obligation described above are as follows:

(In millions)
2018
2019
2020
2021
2022
2023 through 2027

6
6
7
7
7
47

Investment Objectives and Fair Value Measurement

The general investment objectives of the retirement plan include maximizing the return within reasonable and
prudent levels of risk and controlling administrative and management costs. The targeted asset allocation is weighted
equally between equity and fixed income investments. 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, including derivatives, but our exposure to
derivatives currently is not material. We intend that the long-term capital growth of the retirement plan, together with
employer contributions, will provide for the payment of the benefit obligations.

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

The measurement of fair value is based on a three-tier hierarchy, which prioritizes the inputs used in measuring
fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level
2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and
Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop
its own assumptions. Changes in economic conditions or model-based valuation techniques may require the transfer
of financial instruments from one fair value level to another. In such instances, the transfer is reported at the beginning
of the reporting period. For the years ended December 31, 2017 and 2016, there were no transfers between levels.

The fair value measurement of the retirement plan assets as of December 31, 2017, 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

Fair Value Measurements at Reporting Date Using
Significant

Quoted Prices in
Active Markets for Other Observable

Identical Assets
(Level 1)

Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)

30 $

7
38
75 $

— $
—
—
— $

—
—
—
—

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The fair value measurement of the retirement plan assets as of December 31, 2016, 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

Fair Value Measurements at Reporting Date Using
Significant

Quoted Prices in
Active Markets for Other Observable

Identical Assets
(Level 1)

Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)

25 $

7
32
64 $

— $
—
—
— $

—
—
—
—

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.

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.

Rationale for Target

Target unchanged from prior
year. Number of Forced,
Sustained Line Outages,
excluding the "External" cause
classification, for:

ITCTransmission (16 or fewer,
representing top decile
performance); METC (31 or
fewer, representing top decile
performance);

ITC Midwest (70 or fewer,
representing second quartile
performance, no more than 59
of which can cause end-use
customer sustained outages);

Each target worth 5%.

Target is reflective of goal to
complete the normal
maintenance schedule of high
priority maintenance activities.
Complete high priority 2017
Field O&M Initiatives for:

ITCTransmission (15)
METC (13)
ITC Midwest (10)

Each subsidiary target worth
5%.

Target is based on accrued
capital expenditures.

The maximum payout
represents the risk-adjusted
capital investment plan for 2017,
with a threshold level also
established.

Complete $710M of the 2017
Capital Expenditure budget to
achieve 30%; Complete $674M
to achieve 15%.

Total Bonus (as a percent of target bonus level)

____________________________

60%

100%

60%

95%

(1) Net Income was risk-adjusted. Targets were adjusted for amounts recognized for rate refund impacts
associated with the Initial Complaint and the Second Complaint associated with the MISO regional base
ROE and the impacts of the TCJA.

104

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

Measure
Capital Project Plan
Consolidated Net Income
Cash Flow Available for
Distribution
Bonus Multiplier

Threshold
$710M
$331M

Achievement
$777.6M
$323.8M

Multiplier
2.00x
1.00x

Weight
50%
25%

$266M

$300M

2.00x

25%

Result
1.00x
0.25x

0.50x
1.75x

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 1.75x. This performance factor was applied to each executive’s annual corporate performance bonus to produce
a final payment of approximately 166.3% 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 2017 were as follows:

NEO
Linda H. Apsey
Gretchen Holloway
Jon E. Jipping
Daniel J. Oginsky
Christine Mason Soneral

% of Base Salary
100%
100%
100%
100%
100%

Ms. Apsey and Ms. Holloway’s total target cash compensation is near the market median. Total target cash
compensation for the other NEOs is within the target range of the market 50th and 75th percentile, purposely weighted
more towards performance-based compensation, which is consistent with our compensation philosophy.

In February 2017, to recognize Ms. Holloway for assuming the interim Chief Financial Officer role in November
2016 and her expanded responsibilities, the Committee approved a lump sum cash payment in the amount of
$125,000. The Committee also approved a lump sum cash payment in the amount of $11,000 for Mr. Jipping to
recognize his expanded responsibilities with assuming leadership of the grid development initiatives.

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Long-Term Incentives

The Committee provides and maintains a long-term incentive program under the 2017 Omnibus Plan, as
amended July 10, 2017 (the “2017 Omnibus Plan”). In February 2017, the Committee approved grants of service-
based units and performance-based units 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 performance-based units (weighted 67%)
and service-based units (weighted 33%). The performance-based units can be earned for results in two equally-
weighted measures, Total Shareholder Return (relative to a peer group) and cumulative consolidated net income,
over the three-year performance period. 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. The amounts and more detailed terms
of the 2017 service-based unit and performance-based unit 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 2017 awards were made, the award values were targeted to be:

NEO

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

Grant Value
Percent of
Salary

250%
175%
175%
175%
175%

In determining the size of grants under the long-term incentive program and the award mix, the Committee
considered market practice, the recommendation of the CEO (with respect to grants other than to the CEO) in light
of comparisons to benchmarking data, expense to the Company and the practice of other U.S. Fortis subsidiary
companies.

Other Components of Our Executive Compensation Program

Pension Benefits. As is common in our industry and as established pursuant to our initial formation
requirements included in the acquisition agreement with DTE Energy for ITCTransmission, we maintain a tax-qualified
defined benefit retirement plan for eligible employees, comprised of a traditional pension component and a cash
balance component. All employees, including the NEOs, participate in either the traditional component or the cash
balance component. We have also established a supplemental nonqualified, noncontributory retirement benefit plan
for selected management employees: the Executive Supplemental Retirement Plan, or ESRP, in which all of the
NEOs participate. This plan provides for benefits that supplement those provided by our qualified defined benefit
retirement plan. Benefits payable to the NEOs pursuant to the retirement plans are set by the terms of that plan. 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

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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.

None of the NEOs are reimbursed for income taxes associated with the value of the perquisites. Our
employment agreements provide for limited tax gross-ups following termination in some circumstances. 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.

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 officer from the Company 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 officer 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.

Retention Program

In May 2016, as contemplated by the Merger Agreement, we adopted a retention program for the retention
of key talent for the period commencing on the date of the Merger Agreement through the one-year anniversary of
the effective time of the Merger, pursuant to which our executive officers were granted the opportunity to earn a
retention bonus. Under the terms of the retention award letters, recipients received 30% of the retention award as
long as they were employed by the Company on the effective date, and received the remaining 70% if they remained
employed by the Company through the first anniversary of the effective date, October 2017. The amount of each
named executive officer’s total retention bonus amount, which were fully paid as of October 2017, is listed below:

NEO

Retention Award

Linda Apsey
Gretchen Holloway
Jon Jipping
Daniel Oginsky
Christine Mason Soneral

921,000
200,000
753,000
634,500
525,000

Employment Agreement Amendment — Mason Soneral

In October 2016, to address cutback language in her employment agreement that could have caused her
to be treated differently than other NEOs, the employment agreement of Ms. Mason Soneral was amended to (1)
have the annual bonus (with the exception of the total shareholder return component which was paid out pursuant
to the terms of the Merger Agreement) payable in the ordinary course in accordance with her respective employment
agreement and the Company’s past practices based on actual 2016 performance; (2) have a portion of her Company

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performance shares canceled; and (3) provide for payment of additional cash compensation in a comparable amount
over five installments following the Merger, contingent on continued employment with the Company on each
installment date. Ms. Mason Soneral received total retention payments of $162,399 payable in five equal installments
paid on the first payroll date following the first day of each fiscal quarter beginning January 1, 2017.

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.

RHYS D. EVENDEN
A. DOUGLAS ROTHWELL

BARRY V. PERRY
THOMAS G. STEPHENS

SANDRA E. PIERCE

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Summary Compensation

The following table provides a summary of compensation paid or accrued by the Company and its subsidiaries
to or on behalf of the NEOs for services rendered by them during each of the last three calendar years, as required
by 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

Salary ($)

(c)

Bonus
($) (1)

(d)

Stock Awards
($) (2)

(e)

Option
Awards
($) (2)

(f)

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

Non-Equity
Incentive
Plan
Compensatio
n ($) (3)

All Other
Compensat
ion ($) (5)

(g)

(h)

(i)

Total ($)

(j)

725,000

644,700

1,760,834

— $

1,205,313

232,747

57,751

$ 4,626,345

635,146

616,362

317,981
210,116

529,289

503,931

445,327

424,627

659,662

222,164

265,000
60,000

538,100

539,333

207,775

444,150

454,458

153,055

362,404

529,899

351,346

524,557

1,074,490

—

1,244,401

744,344

342,146

598,650

552,539
139,761

909,553

878,517

608,587

765,053

740,250

512,812

620,551

612,487

—
—

—

279,734

—

235,714

—

291,249

41,875

80,454
71,163

345,722

365,553

82,651

177,356

213,915

13,883

41,301

37,990

33,126
31,312

37,694

37,269

36,010

35,972

35,497

26,869

3,946,249

2,603,531

1,830,975
680,689

3,249,796

3,307,218

2,208,138

2,615,983

2,696,727

1,779,385

581,875
168,337

889,438

982,615

489,450

748,125

827,980

412,425

606,813

146,625

36,378

2,302,670

695,590

135,364

35,675

2,355,019

Name

(a)

Linda H. Apsey,
President &
CEO

Gretchen L.
Holloway
SVP & CFO (6)

Jon E. Jipping,
EVP & COO

Daniel J.
Oginsky,
EVP & CAO

Christine
Mason Soneral,
SVP & General
Counsel

Year

(b)

2017

2016

2015

2017
2016

2017

2016

2015

2017

2016

2015

2017

2016

2015

328,777

38,861

775,093

$ 195,034

341,250

112,077

13,950

$ 1,805,042

____________________________

(1)

The compensation amounts reported in this column include, (a) awards under the Special Bonus Plan, (b)
bonuses paid in connection with project milestones and (c) retention bonuses. Bonuses paid in connection
with our annual corporate performance plan are reported in the “Non-Equity Incentive Plan Compensation”
column of the Summary Compensation Table. Bonuses under the Special Bonus Plan, were awarded at the
sole discretion of the Committee and were equal to per share dividend amounts paid by the Company
multiplied by the number of options granted in 2003 and 2005. These options were exercised and the Special
Bonus Plan expired in 2015. In 2015 and 2016, the NEOs, received certain project-related bonuses in
recognition of the successful completion of various transmission development milestones. In 2016, Ms.
Mason Soneral received $300,000 since the Merger was closed before December 31, 2016. In 2016, all of
the NEOs received 30% of their retention award due to the closing of the Merger and, in October 2017, they
received the remaining 70% of their retention award. See “Compensation Discussion and Analysis - Retention
Program”. In 2017, Ms. Mason Soneral earned $162,399 in accordance with the retention payments related
to her employment agreement amendment. See “Compensation Discussion and Analysis - Employment
Agreement Amendment - Mason Soneral”. 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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Table of Contents

Name

Year

Special
Bonus ($)

Retention
Bonus ($)

Merger
Completion
($)

Other
Bonuses ($)

Total Bonus
($)

Linda H.
Apsey

Gretchen L.
Holloway

Jon E.
Jipping

Daniel J.
Oginsky

Christine
Mason
Soneral

2017

2016

2015

2017

2016

2017

2016

2015

2017

2016

2015

2017

2016

2015

— $

644,700

— $

644,700

—

26,136

—

276,300

—

140,000

60,000

527,100

225,900

—

444,150

190,350

—

529,899

157,500

—

300,000

383,362

222,164

125,000

—

11,000

313,433

181,639

—

264,108

153,055

—

67,057

659,662

222,164

265,000

60,000

538,100

539,333

207,775

444,150

454,458

153,055

529,899

524,557

— $

38,861

(2)

The amounts reported in these columns represent the fair value, of stock option, performance share, restricted
shares, performance-based units and service-based unit awards granted to the NEOs under the 2017
Omnibus Plan, 2015 LTIP, and the 2006 LTIP in accordance with Financial Accounting Standards Board
Accounting Standards Codification Topic 718, or ASC 718.

The grant date fair value of the service-based unit awards is based on the applicable share price on the
grant date. The grant date fair value of the performance-based units 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 service-based unit
awards and performance-based unit awards are liability awards, subject to remeasurement through the
vesting date, and settled in cash, see “Grants of Plan-Based Awards”. The 2016 awards only included
restricted shares; performance shares and restricted shares were awarded in 2015.

The grant date fair value of the stock options was determined in accordance with ASC 718 using a Black-
Scholes option pricing model and the following assumptions; options have not been granted since 2015:

Remaining
Future Life of
Option

Expected
Volatility

Risk Free
Interest Rate

Expected
Life (Years)

Expected
Dividend
Yield

Share Price at
Grant Date

—

7.3

—%

18.6%

—%

1.81%

—

—% $

—

1.59% $

35.91

Year

2017

2016

2015

(3)

(4)

The amounts reported in this column include cash awards tied to the achievement of annual Company
performance goals under our bonus plan in effect for each of 2017, 2016 and 2015. For information regarding
the corporate goals for 2017, see “Compensation Discussion and Analysis - Key Components of Our NEO
Compensation Program - Annual Corporate Performance Bonus".

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 4.44% in 2015, 4.15%
in 2016 and 3.67% in 2017.

(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,

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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 plane. 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 2017, 2016 and 2015 are itemized in the table below as required by applicable
SEC rules.

Name

Linda H.
Apsey

Gretchen L.
Holloway

Jon E.
Jipping

Daniel J.
Oginsky

Christine
Mason
Soneral

Year

2017

2016

2015

2017

2016

2017

2016

2015

2017

2016

2015

2017

2016

2015

401(k)
Match

Tax
Reimbursements

Personal
Use of
Company
Aircraft

Other
Benefits

Total

$ 14,400

— $ 12,752

30,599

57,751

14,300

14,400

14,300

16,200

15,900

14,300

14,400

14,300

14,400

14,300

—

27,001

23,690

18,726

17,012

21,494

21,369

21,710

21,572

21,197

12,569

21,978

21,375

41,301

37,990

33,126

31,312

37,694

37,269

36,010

35,972

35,497

26,869

36,378

35,675

$ 13,950

— $

13,950

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.

(6)

Ms. Holloway became Vice President, Interim Chief Financial Officer and Treasurer in October 2016 and
was appointed to Senior Vice Present and Chief Financial Officer in July 2017. In accordance with SEC
rules, we have excluded Ms. Holloway’s compensation for 2015 as she was not an executive officer during
that year.

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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 2017.
In this table, a service-based unit is referred to as an “SBU”, a performance-based unit is referred to as a
“PBU” and an award under the annual corporate performance bonus plan is referred to as an “ACPB”.

Grants of Plan-Based Awards Table

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)

3/8/2017

SBU

— $

—

19,590

$ 617,826

19,590

39,181

78,362

— 1,143,008

—

Linda H.
Apsey

3/8/2017

PBU

ACPB

3/8/2017

SBU

3/8/2017

PBU

ACPB

3/8/2017

SBU

3/8/2017

PBU

ACPB

3/8/2017

SBU

3/8/2017

PBU

ACPB

3/8/2017

SBU

3/8/2017

PBU

Gretchen L.
Holloway

Jon E.
Jipping

Daniel J.
Oginsky

Christine
Mason
Soneral

—

725,000

1,450,000

—

350,000

700,000

—

535,000

1,070,000

—

450,000

900,000

—

6,147

193,863

6,147

12,295

24,590

—

10,119

20,239

40,478

—

8,511

17,023

34,046

—

358,676

—

10,119

319,131

—

590,422

—

8,512

268,450

—

496,603

—

6,904

217,737

6,904

13,808

27,616

—

402,814

ACPB

— $ 365,000

$ 730,000

—

— $

—

____________________________

(1)

(2)

(3)

The amount shown in Column (d) represents the potential payout for the annual corporate performance
bonus 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 annual
corporate performance bonuses, see “Compensation Discussion and Analysis — Key Components of Our
NEO Compensation Program — Annual Corporate Performance Bonus.”

Payment of each performance-based unit 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 2017 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 Agreement.”

Grant Date Fair Value consists of service-based units and performance-based units awarded under the 2017
Omnibus Plan with a grant date of March 8, 2017. The performance-based units reflected here are recorded
at fair value at the date of grant, which was $29.17 per share. The service-based units reflected here are
recorded at fair value at the date of grant, which was $31.53 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

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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 service-based units and performance-based units 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 2017 to the NEOs were made under the 2017 Omnibus Plan pursuant to terms stated in
the service-based unit and performance-based unit award agreements.

Performance-Based Unit Award Agreements

The performance-based unit award agreements entered into with each NEO in 2017 (each a “PBU
Agreement”) provide generally that the award will vest on December 31, 2019 (the “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
Vesting Date. One-half of the Target Number of units shall be related to the Fortis Total Shareholder Return goal
(the “TSR goal”) and one-half of the Target Number of shares 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, 2017 through December 31, 2019 (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
performance-based units 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 units 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 2017 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
Ameren Corp.
Atmos Energy Corp.
Canadian Utilities Ltd.
CenterPoint Energy Inc.
CMS Energy Corp.
Consolidated Edison Inc.
DTE Energy Co.
Edison International

Emera Inc.
Energy Corp.
Eversource Energy
FirstEnergy Corp.
Great Plains Energy Inc.
Hydro One Ltd.
NiSource Inc.
OGE Energy Corp.

Pinnacle West Capital
PPL Corp.
Public Svc Enterprise Group
SCANA Corp.
Sempre Energy
UGI Corp.
WEC Energy Group
Xcel Energy

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

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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 Vesting Date due to death or disability, the grantee will
receive, following the Vesting Date, the number of units to which the grantee would have otherwise been entitled if
the grantee had remained employed through the Vesting Date. If the grantee ceases to be employed before the
Vesting Date due to “Retirement” or “Involuntary Termination Without Cause,” and the grantee has been in service
of the Company for one year or more after the grant date, the grantee will receive, following the Vesting Date, a pro
rata portion (based on the period served from the grant date to termination) of the number of units to which the
grantee would have otherwise been entitled. If termination occurs prior to the Vesting Date other than as a result of
death, disability, Retirement or Involuntary Termination Without Cause, grantee will forfeit the award. “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 performance-based

units 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 performance-based units is the product of (i) the higher of (A)
100% of the target number of performance-based units 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 units 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 performance-based units in the grantee’s account
on the date that the dividends are paid, including performance-based units 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” performance-based units shall have a Vesting Date which is the
same as the Vesting Date for the performance-based units in respect of which such additional performance-based
units are credited.

Service-Based Unit Award Agreements

The service-based unit award agreements entered into with each of our NEOs in 2017 (each a “SBU
Agreement”) provide generally that, so long as the grantee remains employed by the Company, the service-based
units fully vest upon the earlier of (i) December 31, 2019 (the “Vesting Date”) or (ii) the grantee's death or disability.
If the grantee ceases to be employed before the Vesting Date due to “Retirement” or “Involuntary Termination Without
Cause” and the grantee has been in service of the Company for one year or more after the grant date, the grantee
will receive a pro rata portion (based on the period served from the grant date to termination) of the number of service-
based units to which the grantee would have otherwise been entitled. If termination occurs prior to the Vesting Date
other than as a result of death, disability, Retirement or Involuntary Termination Without Cause, grantee will forfeit
the award. Upon a Change of Control, all unvested service-based units 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 service-based units 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 service-based units and performance-based units

that have not vested as of the end of 2017 held by the NEOs.

Number of Shares or
Units of Stock That
Have Not Vested (#)
(SBUs) (2)

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) (3)

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)

20,117 $

6,313

10,391

8,741

7,090 $

737,707

231,479

381,054

320,539

259,986

40,236 $

1,475,451

12,626

20,784

17,481

14,180 $

462,997

762,146

641,040

519,972

Name

(a)

Linda H. Apsey

Gretchen L. Holloway

Jon E. Jipping

Daniel J. Oginsky

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 as of December 29, 2017 ($36.67).

(2) The unvested service-based units generally vest on December 31, 2019.

(3) The unvested performance-based units generally vest on December 31, 2019. The award contains
performance conditions established by the Committee. In order for performance-based units to vest such performance
conditions must be achieved. Amounts reported reflect performance-based unit payouts as if the target performance
goals have been achieved.

Equity grants made to NEOs in 2017 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.

Option Exercises and Stock Vested

The NEOs did not have any option exercises or equity awards that vested in 2017.

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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

ESRP

Cash Balance Component

Total Qualified Plan

Christine Mason
Soneral

Number of Years
Credited Service (#)
(1)

Present Value of
Accumulated
Benefit ($)(2)

Payments During
Last Fiscal Year
($)

(c)

(d)

(e)

23.58

N/A

14.83

13.95

2.91

27.03

12.92

13.20

10.29

373,576

36,447

410,023

1,422,819

235,678

100,652

1,410,494

1,203,671

298,264

957,202

231,647

475,595

N/A

ESRP

10.29

____________________________

(1) Credited service is estimated as of December 31, 2017 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, 2017 (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, 2017. The rate at which future expected
benefit payments were discounted in calculating present values was 3.67%, the same rate used for fiscal
year-end 2017 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 2.78% for 2018 and 4.5% 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 for the respective NEOs
were as follows:

Ms. Apsey:

Ms. Holloway

Mr. Jipping:

Mr. Oginsky

Age 58

Ms. Mason Soneral Age 58

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.

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Benefits provided under the Qualified Plan are based on compensation up to a compensation limit under
the Internal Revenue Code (which was $270,000 in 2017, 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
$215,000 payable as a single life annuity beginning at normal retirement age in 2017).

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 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 65, is

approximately $106,700. 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 ($270,000 in 2017). 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 2017 is approximately $351,000, Ms. Holloway’s is approximately $213,000, Ms. Mason
Soneral’s is approximately $212,000, and Mr. Oginsky’s is approximately $272,000.

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

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highly paid employees. The NEO’s cash balance account is increased by any amounts shifted from the ESRP. The
purpose of the benefit is to provide the NEO and the Company the tax advantages of providing benefits through a
tax qualified plan.

Ms. Apsey has received ESRP shift additions to her Qualified Plan cash balance account. There was no
shift of compensation credits for 2017, although previous shifts have continued to earn interest credits. As of year-
end 2017, her ESRP shift balance was approximately $34,000.

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. Pursuant to the terms of the plan, Ms. Holloway became fully vested at the time of the
Merger.

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, 2017, 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

1,335,751

90,920

1,165,089

874,474

435,937

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. Currently none of our NEOs participate in this plan.

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

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2016 in connection with her appointment as President and Chief Executive Officer and the term of the agreement
is now set to expire December 31, 2018, subject to the automatic one-year renewal provision described above. Ms.
Mason Soneral’s agreement was modified in October 2016 as described in “Compensation Discussion and Analysis
— Employment Agreement Amendments — Mason Soneral.” The following describes the material terms of the
employment agreements, as amended, with the NEOs who remained employed by the Company on December 31,
2017.

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 in 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. The benefits include:

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 annual bonuses,
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 annual bonus for the year of termination, based upon the Company’s actual
achievement of the performance targets for such year as determined under the annual bonus plan and paid
at the time that such bonus would normally be paid;

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•

eligibility to continue coverage under our active medical, dental and vision plans subject to applicable COBRA
rules; if such coverage is elected, we will reimburse the NEO for the shorter of 18 months, or until the NEO
becomes eligible for coverage under another employer-sponsored group plan, in an amount equal to our
periodic cost of such coverage for other executives, plus a tax gross-up amount;

outplacement services for up to two years; and

for Ms. Apsey, deemed satisfaction of the eligibility requirements of our Postretirement Welfare Plan for
purposes of participation therein; and 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, 2017.

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:

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)

— $

1,450,000

3,149,345

— $

—

725,000

1,205,313

—

25,000

28,809

737,690

490,918

1,475,451

—

25,000

28,809

—

594,085

— $

3,303,207

6,231,160

2,938,141

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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)

— $

700,000

889,435

— $

—

350,000

581,875

—

25,000

26,580

231,461

154,050

254,204

—

25,000

26,580

462,997

—

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:

— $

1,333,455

2,162,605

1,044,458

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

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

Voluntary
Resignation

Involuntary For
Cause

Involuntary Not-
for-Cause or
Voluntary Good
Reason

Change In
Control (pre-tax)
(3)

Disability

Death (pre-
retirement)(4)

— $

1,070,000

2,436,244

— $

—

535,000

889,438

—

25,000

27,916

381,038

253,584

762,146

—

25,000

27,916

—

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

Total Payout:

— $

2,012,354

4,013,220

1,678,184

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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)

— $

900,000

2,051,238

— $

—

450,000

748,125

—

25,000

27,022

320,532

213,289

641,040

—

25,000

27,022

—

Total Payout:

— $

1,700,147

3,385,206

1,411,572

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)

— $

730,000

1,296,901

— $

—

365,000

606,813

—

25,000

27,796

259,990

173,007

519,972

—

25,000

27,796

—

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:

— $

1,389,609

2,389,507

1,144,962

____________________________

(1) All scenarios include the value of severance. For Ms. Apsey, the value of the Postretirement Welfare Plan
is additionally included where applicable. The Pension Benefits Table assumes that none of the executives
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 table.

(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 $254,204 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, 2017. 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 ($112,159 for Ms. Apsey, $819,642 for Mr. Jipping,
$108,507 for Mr. Oginsky, $58,974 for Ms. Mason Soneral, and $35,520 for Ms. Holloway) 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 since Ms. Apsey's employment agreement includes a provision for deemed
satisfaction of the eligibility requirements when terminated under these scenarios. It is assumed she would
commence her 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 3.75%, the same rate
used for fiscal year-end 2017 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,
2017. The above table does not reflect the reduction in the present value ($141,049 except for death) due
to applying the 90% early retirement factor.

(7) Under the 2017 Omnibus Plan, outstanding and unvested service-based units and respective dividend
equivalents shall be deemed to be vested service-based units 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 service-based units and respective
dividend equivalents shall be deemed to be vested service-based units and redeemable 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 service-based units 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, service-based units and respective dividend equivalents shall be deemed to have vested
pro-rata based on the period served from the grant date to termination.

(8) Under the 2017 Omnibus Plan, outstanding and unvested performance-based unit 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 performance-based units 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 performance-based unit 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 performance-based unit 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, performance-based unit awards and respective dividend equivalents
shall be deemed to have vested pro-rata based on the period served from grant date to termination.

Upon death or disability, a NEO (or his or her estate) receives a pro rata portion of his or her current year
target bonus. All balances under the cash balance and ESRP shift components of the Qualified Plan, and the ESRP
balance (vested portion only for disability), are immediately payable. If the NEO has 10 years of service after age
45, then the NEO (and his or her spouse) is eligible for retiree medical benefits.

Pay Ratio

As required by the 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 2017, our last completed fiscal year:

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the median of the annual total compensation of all employees of the Company (other than Ms.

Apsey), was $142,593; and

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

$4,626,345.

Based on this information, Ms. Apsey’s 2017 annual total compensation was estimated to be 32 times the
median annual total compensation for all employees, other than Ms. Apsey. Ms. Apsey received a retention payment
in October 2017 of $644,700 due to the Merger. This type of payment is not part of her regular compensation and if
excluded from the calculation, the pay ratio was estimated to be 28 times the median annual total compensation for
all employees.

We determined that, as of December 31, 2017, our employee population consisted of 669 individuals with
all of those individuals located in the United States. To identify the “median employee” from our employee population,
excluding Ms. Apsey, we utilized a consistently applied compensation measure that included the sum of each
employee’s 2017 annualized base salary as of December 31, 2017 as reflected in our payroll records, and target
2017 awards made under our annual corporate performance plan and 2017 Omnibus Plan that were not paid in
2017. We arrayed these values to select our “median employee”.

Using our “median employee” and Ms. Apsey, we calculated the 2017 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 2017.

Non-Employee Director Compensation Table

Name (1)

(a)

Fees Earned or
Paid in Cash ($)
(2)

Stock Awards ($)

Total ($)

(b)

(c)

(h)

Robert A. Elliott

Albert Ernst

Rhys D. Evenden (3)

James P. Laurito

Barry V. Perry

Sandra E. Pierce

Kevin L. Prust

A. Douglas Rothwell

Thomas G. Stephens

Joseph L. Welch

125,000

— $

125,000

132,500

24,457

132,500

150,000

—

125,000

132,500

24,457

132,500

150,000

____________________________

(1) Ms. Pierce and Messrs. Elliott, Ernst, Prust and Stephens were appointed to the Board, effective January
1, 2017. Mr. Rothwell was appointed to the Board on October 20, 2017. Mr. Rothwell’s cash retainer
was prorated for the length of service rendered in fiscal year 2017.

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

Welch only).

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

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 $125,000. In addition, we pay an additional cash retainer
of $7,500 annually to the chair of each Board committee and $25,000 annually to our chairman. We do not pay per-
meeting fees under the policy. Beginning in calendar year 2017, non-employee directors were and will continue to
be reimbursed for their out-of-pocket expenses.

We maintain a Director Deferred Compensation Plan under which nonqualified deferred compensation is

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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.

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, 2018, 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, 2018 or within 60 days thereafter through the exercise
of any stock option or other right. Unless otherwise indicated, each holder has sole investment and voting power
with respect to the shares set forth in the following table:

Name of Beneficial Owner

Linda H. Apsey
Gretchen L. Holloway
Jon E. Jipping
Daniel J. Oginsky
Christine Mason Soneral
Robert A. Elliott
Albert Ernst
Rhys D. Evenden
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 (15 persons)

____________________________

Number of
Shares
Beneficially
Owned

Percent of
Class

Fortis Inc.
Number of
shares
Beneficially
Owned

—
—
—
—
—
—
—
—
—
—
—
—
—
—
—

—

—%
53,889
—%
4,194
—%
120,000
—%
72,621
—%
—
—%
—
—%
13,073 (2)
—%
—
1,965
—%
—% 787,975 (3)
—
—%
—
—%
—
—%
—%
2,098
—% 1,178,328 (1)

Percent
of Class
*
*
*
*
—
—
*
—
—
*
—
—
—
*
*

—%

2,234,143

* Less than one percent

(1) 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,
and disclaims ownership of such shares.

(2)

(3)

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

Includes 29,825 shares owned by the spouse and children of Mr. Perry as well as
546,377 shares that may be acquired upon exercise of options that are currently
exercisable or become exercisable prior to April 2, 2018.

Investment Holdings, which owns all of our outstanding common stock, is 80.1% owned by FortisUS and

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19.9% owned by Eiffel. FortisUS is a wholly-owned subsidiary of Fortis.

At December 31, 2017, there were no securities authorized for issuance under any compensation plans

of ITC Holdings Corp.

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 Governance and Human Resources 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 Governance and Human Resources
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 Governance and Human Resources 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 2017 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
$507,889 during 2017.

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 Investment Holdings; (b) is designated as an independent
director by the Investment Holdings’ board and Company Board, or the shareholders of Investment Holdings; (c)
is not a director that is nominated by Finn Investment Pte Ltd or any successor or permitted assign thereof and
appointed as a member of the 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 Investment Holdings or the Company);
or (ii) an officer or employee of Investment Holdings, the Company, FortisUS or any of their affiliates; and (e) would
meet the definition of “independent director” under the New York Stock Exchange Listed Company Manual if such
director were a member of the board of directors of Fortis, FortisUS, Investment Holdings, or the Company

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(assuming, in the case of FortisUS, Investment Holdings and the Company, that such entities were listed on the
New York Stock Exchange).

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 2017 and 2016:

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

____________________________

2017
1,888,000 $
329,000
187,000
127,000
2,531,000 $

2016
1,866,000
924,000
753,000
10,000
3,553,000

(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 due diligence support relating to merger and acquisition activity and the audit of
our employee benefit plans and accounting consultations. The fees also include amounts for the services
provided in connection with our securities offerings and accounting consultations and audits in connection
with acquisitions.

(3) Tax fees were professional services for federal and state tax compliance, tax advice and tax planning,

including services to support merger and acquisition activity.

(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 the Deloitte Power and Utilities
Seminar and Utility Accounting Workshop, and assessment of our ERM Program.

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 2017.

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.

(a)

(1) Financial Statements:

Management’s Report on Internal Control over Financial Reporting

Report of Independent Registered Public Accounting Firm

Consolidated Statements of Financial Position as of December 31, 2017 and 2016

Consolidated Statements of Operations for the Years Ended December 31, 2017, 2016 and 2015

Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2017, 2016 and 2015

Consolidated Statements of Changes in Stockholder's Equity for the Years Ended December 31, 2017, 2016 and

2015

Consolidated Statements of Cash Flows for the Years Ended December 31, 2017, 2016 and 2015

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)

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Exhibit No.

Description of Exhibit

4.10

4.12

4.14

4.17

4.18

4.19

4.20

4.21

4.23

4.24

4.25

4.26

4.27

4.28

4.29

4.30

4.31

4.32

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)

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)

Fourth Supplemental Indenture, dated as of March 25, 2008, between International Transmission Company
and The Bank of New York Trust Company, N.A., as trustee, to the First Mortgage and Deed of Trust dated
as of July 15, 2003 (filed with Registrant’s Form 8-K on March 27, 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)

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Exhibit No.

Description of Exhibit

4.33

4.34

4.35

4.36

4.38

4.39

4.40

4.41

4.42

4.43

4.44

4.45

4.46

4.47

Indenture, dated as of April 18, 2013, between ITC Holdings Corp. and Wells Fargo Bank, National
Association, as trustee (including form of note) (filed with Registrant’s Form S-3 on April 18, 2013)

First Supplemental Indenture, dated as of July 3, 2013, between ITC Holdings Corp. and Wells Fargo
Bank, National Association, as trustee (including forms of notes) (filed with Registrant’s Form 8-K on July
3, 2013)

Fifth Supplemental Indenture, dated as of August 7, 2013, between International Transmission Company
and The Bank of New York Mellon Trust Company, N.A. (as successor to BNY Midwest Trust Company),
as trustee (including form of bonds) (filed with Registrant’s Form 8-K on August 16, 2013)

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)

*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)

*10.109

*10.110

*10.111

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)

131

Table of Contents

Exhibit No.

*10.120

*10.122

10.126

10.127

10.128

10.129

10.130

*10.150

10.157

10.158

10.159

10.160

Description of Exhibit

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)

ITC Holdings Revolving Credit Agreement, dated as of March 28, 2014, among ITC Holdings Corp., the
various financial institutions and other persons from time to time parties thereto as lenders, JPMorgan
Chase Bank, N.A., as administrative agent, J.P. Morgan Securities LLC, Barclays Bank PLC and Wells
Fargo Securities, LLC, as joint lead arrangers and joint bookrunners, and Barclays Bank PLC and Wells
Fargo Bank, National Association, as syndication agents (filed with Registrant’s Form 8-K on March 28,
2014)

ITCTransmission Revolving Credit Agreement, dated as of March 28, 2014, among International
Transmission Company, the various financial institutions and other persons from time to time parties thereto
as lenders, JPMorgan Chase Bank, N.A., as administrative agent, J.P. Morgan Securities LLC, Barclays
Bank PLC and Wells Fargo Securities, LLC, as joint lead arrangers and joint bookrunners, and Barclays
Bank PLC and Wells Fargo Bank, National Association, as syndication agents (filed with Registrant’s Form
8-K on March 28, 2014)

METC Revolving Credit Agreement, dated as of March 28, 2014, among Michigan Electric Transmission
Company, LLC, the various financial institutions and other persons from time to time parties thereto as
lenders, JPMorgan Chase Bank, N.A., as administrative agent, J.P. Morgan Securities LLC, Barclays Bank
PLC and Wells Fargo Securities, LLC, as joint lead arrangers and joint bookrunners, and Barclays Bank
PLC and Wells Fargo Bank, National Association, as syndication agents (filed with Registrant’s Form 8-
K on March 28, 2014)

ITC Midwest Revolving Credit Agreement, dated as of March 28, 2014, among ITC Midwest LLC, the
various financial institutions and other persons from time to time parties thereto as lenders, JPMorgan
Chase Bank, N.A., as administrative agent, J.P. Morgan Securities LLC, Barclays Bank PLC and Wells
Fargo Securities, LLC, as joint lead arrangers and joint bookrunners, and Barclays Bank PLC and Wells
Fargo Bank, National Association, as syndication agents (filed with Registrant’s Form 8-K on March 28,
2014)

ITC Great Plains Revolving Credit Agreement, dated as of March 28, 2014, among ITC Great Plains, LLC,
the various financial institutions and other persons from time to time parties thereto as lenders, JPMorgan
Chase Bank, N.A., as administrative agent, J.P. Morgan Securities LLC, Barclays Bank PLC and Wells
Fargo Securities, LLC, as joint lead arrangers and joint bookrunners, and Barclays Bank PLC and Wells
Fargo Bank, National Association, as syndication agents (filed with Registrant’s Form 8-K on March 28,
2014)

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)

Amendment No. 1, dated as of April 7, 2016, to the Revolving Credit Agreement, dated as of March 28,
2014, by and among ITC Holdings, as the borrower, various financial institutions and other persons from
time to time parties thereto as lenders, JPMorgan Chase Bank, N.A., as administrative agent, J.P. Morgan
Securities LLC, Barclays Bank PLC and Wells Fargo Securities, LLC, as joint lead arrangers and joint
bookrunners, and Barclays Bank PLC and Wells Fargo Bank, National Association, as syndication agents
(filed with Registrant’s Form 8-K on April 11, 2016)

Amendment No. 1, dated as of April 7, 2016, to the Revolving Credit Agreement, dated as of March 28,
2014, by and among ITCTransmission, as the borrower, various financial institutions and other persons
from time to time parties thereto as lenders, JPMorgan Chase Bank, N.A., as administrative agent, J.P.
Morgan Securities LLC, Barclays Bank PLC and Wells Fargo Securities, LLC, as joint lead arrangers and
joint bookrunners, and Barclays Bank PLC and Wells Fargo Bank, National Association, as syndication
agents (filed with Registrant’s Form 8-K on April 11, 2016)

Amendment No. 1, dated as of April 7, 2016, to the Revolving Credit Agreement, dated as of March 28,
2014, by and among METC, as the borrower, various financial institutions and other persons from time to
time parties thereto as lenders, JPMorgan Chase Bank, N.A., as administrative agent, J.P. Morgan
Securities LLC, Barclays Bank PLC and Wells Fargo Securities, LLC, as joint lead arrangers and joint
bookrunners, and Barclays Bank PLC and Wells Fargo Bank, National Association, as syndication agents
(filed with Registrant’s Form 8-K on April 11, 2016)

Amendment No. 1, dated as of April 7, 2016, to the Revolving Credit Agreement, dated as of March 28,
2014, by and among ITC Midwest, as the borrower, various financial institutions and other persons from
time to time parties thereto as lenders, JPMorgan Chase Bank, N.A., as administrative agent, J.P. Morgan
Securities LLC, Barclays Bank PLC and Wells Fargo Securities, LLC, as joint lead arrangers and joint
bookrunners, and Barclays Bank PLC and Wells Fargo Bank, National Association, as syndication agents
(filed with Registrant’s Form 8-K on April 11, 2016)

132

Table of Contents

Exhibit No.

10.161

*10.163

*10.165

*10.166

*10.168

*10.172

*10.173

*10.174

*10.175

*10.176

*10.177

*10.178

*10.179

10.180

10.181

10.182

10.183

10.184

Description of Exhibit

Amendment No. 1, dated as of April 7, 2016, to the Revolving Credit Agreement, dated as of March 28,
2014, by and among ITC Great Plains, as the borrower, various financial institutions and other persons
from time to time parties thereto as lenders, JPMorgan Chase Bank, N.A., as administrative agent, J.P.
Morgan Securities LLC, Barclays Bank PLC and Wells Fargo Securities, LLC, as joint lead arrangers and
joint bookrunners, and Barclays Bank PLC and Wells Fargo Bank, National Association, as syndication
agents (filed with Registrant’s Form 8-K on April 11, 2016)

Retention Award Letter, dated May 23, 2016, between ITC Holdings Corp. and Linda H. Blair (filed with
Registrant’s Form 10-Q for the quarter ended June 30, 2016)

Retention Award Letter, dated May 23, 2016, between ITC Holdings Corp. and Jon E. Jipping (filed with
Registrant’s Form 10-Q for the quarter ended June 30, 2016)

Retention Award Letter, dated May 23, 2016, between ITC Holdings Corp. and Daniel J. Oginsky (filed
with Registrant’s Form 10-Q for the quarter ended June 30, 2016)

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)

Retention Award Letter, dated May 19, 2016 between ITC Holdings Corp. and Christine Mason Soneral
(filed with Registrant’s 2016 Form 10-K)

Retention Award Letter, dated March 16, 2016 between ITC Holdings Corp. and Gretchen L. Holloway
(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)

Term Loan Credit Agreement, dated as of March 23, 2017, among ITC Holdings Corp., the various
financial institutions and other persons from time to time parties thereto as lenders and JPMorgan
Chase Bank, N.A., as administrative agent, lead arranger and sole bookrunner (filed with Registrant’s
Form 8-K on March 27, 2017)

Term Loan Credit Agreement, dated as of March 23, 2017, among International Transmission
Company, the various financial institutions and other persons from time to time parties thereto as
lenders and PNC Bank, National Association, as administrative agent (filed with Registrant’s Form 8-K
on March 27, 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)

133

Table of Contents

Exhibit No.

10.185

10.186

10.187

10.188

10.189

12.1

31.1

31.2

Description of Exhibit

ITCTransmission Revolving Credit Agreement, dated as of October 23, 2017, among International
Transmission Company, with the banks, financial institutions and other institutional lenders listed on the
respective signature pages thereof, JPMorgan Chase Bank, N.A., as administrative agent for the
Lenders, JPMorgan Chase Bank, N.A., Barclays Bank PLC, Wells Fargo Securities, LLC, The Bank of
Nova Scotia and Mizuho Bank, Ltd., as joint lead arrangers and joint bookrunners, Barclays Bank PLC
and Wells Fargo Bank, National Association, as co-syndication agents and The Bank of Nova Scotia
and Mizuho Bank, Ltd. as co-documentation agents (filed with Registrant’s Form 8-K on October 23,
2017)

METC Revolving Credit Agreement, dated as of October 23, 2017, among Michigan Electric
Transmission Company, LLC, with the banks, financial institutions and other institutional lenders listed
on the respective signature pages thereof, JPMorgan Chase Bank, N.A., as administrative agent for the
Lenders, JPMorgan Chase Bank, N.A., Barclays Bank PLC, Wells Fargo Securities, LLC, The Bank of
Nova Scotia and Mizuho Bank, Ltd., as joint lead arrangers and joint bookrunners, Barclays Bank PLC
and Wells Fargo Bank, National Association, as co-syndication agents and The Bank of Nova Scotia
and Mizuho Bank, Ltd. as co-documentation agents (filed with Registrant’s Form 8-K on October 23,
2017)

ITC Midwest Revolving Credit Agreement, dated as of October 23, 2017, among ITC Midwest LLC, with
the banks, financial institutions and other institutional lenders listed on the respective signature pages
thereof, JPMorgan Chase Bank, N.A., as administrative agent for the Lenders, JPMorgan Chase Bank,
N.A., Barclays Bank PLC, Wells Fargo Securities, LLC, The Bank of Nova Scotia and Mizuho Bank,
Ltd., as joint lead arrangers and joint bookrunners, Barclays Bank PLC and Wells Fargo Bank, National
Association, as co-syndication agents and The Bank of Nova Scotia and Mizuho Bank, Ltd. as co-
documentation agents (filed with Registrant’s Form 8-K on October 23, 2017)

ITC Great Plains Revolving Credit Agreement, dated as of October 23, 2017, among ITC Great Plains,
LLC, with the banks, financial institutions and other institutional lenders listed on the respective
signature pages thereof, JPMorgan Chase Bank, N.A., as administrative agent for the Lenders,
JPMorgan Chase Bank, N.A., Barclays Bank PLC, Wells Fargo Securities, LLC, The Bank of Nova
Scotia and Mizuho Bank, Ltd., as joint lead arrangers and joint bookrunners, Barclays Bank PLC and
Wells Fargo Bank, National Association, as co-syndication agents and The Bank of Nova Scotia and
Mizuho Bank, Ltd. as co-documentation agents (filed with Registrant’s Form 8-K on October 23, 2017)

Registration Rights Agreement, dated November 14, 2017 between ITC Holdings Corp., Barclays
Capital Inc., J.P. Morgan Securities LLC, Morgan Stanley & Co. LLC and Wells Fargo Securities, LLC,
on their own behalf and as representatives of each of the other initial purchasers named therein (filed
with Registrant’s Form 8-K on November 15, 2017)

Ratio of Earnings to Fixed Charges for ITC Holdings Corp.

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

101.SCH

XBRL Taxonomy Extension Schema

101.CAL

XBRL Taxonomy Extension Calculation Linkbase

101.DEF

XBRL Taxonomy Extension Definition Database

101.LAB

XBRL Taxonomy Extension Label Linkbase

101.PRE

XBRL Taxonomy Extension Presentation Linkbase

____________________________

Management contract or compensatory plan or arrangement.

134

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
Income tax receivable
Prepaid and other current assets

Total current assets

Other assets

Investment in subsidiaries
Deferred income taxes
Other

Total other assets

TOTAL ASSETS
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities

Intercompany tax payable to subsidiaries
Accrued compensation
Accrued interest
Debt maturing within one year
Other

Total current liabilities

Accrued pension and postretirement liabilities
Other
Long-term debt (net of deferred financing fees and discount of $22 and $16,

respectively)

STOCKHOLDER’S EQUITY

Common stock, without par value, 235,000,000 shares authorized as of December 31,
2017, and 224,203,112 shares issued and outstanding at December 31, 2017 and
2016

Retained earnings
Accumulated other comprehensive income

Total stockholder’s equity

TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY

December 31,

2017

2016

60
21
15
3
99

4,461
141
96
4,698
4,797

— $
28
33
—
8
69
74
6

4
16
17
8
45

4,171
208
78
4,457
4,502

85
14
33
195
13
340
68
1

2,728

2,192

892
1,026
2
1,920
4,797

892
1,007
2
1,901
4,502

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

135

Table of Contents

SCHEDULE I — Condensed Financial Information of Registrant

ITC HOLDINGS CORP.

CONDENSED STATEMENTS OF OPERATIONS (PARENT COMPANY ONLY)

(In millions)
Other income
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

Year Ended December 31,
2016

2015

2017

2 $

(11)
(2)
(120)
(131)
(6)
(125)
444
319 $

1 $

(122)
—
(113)
(234)
(122)
(112)
358
246 $

1
(6)
—
(106)
(111)
(45)
(66)
308
242

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

136

Table of Contents

SCHEDULE I — Condensed Financial Information of Registrant

ITC HOLDINGS CORP.

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (PARENT COMPANY ONLY)

(In millions)
NET INCOME
OTHER COMPREHENSIVE LOSS

Year Ended December 31,
2016

2015

2017

319 $

246 $

242

Derivative instruments (net of tax of $3 and $1 for the years ended

December 31, 2016 and 2015, respectively)

TOTAL OTHER COMPREHENSIVE LOSS, NET OF TAX
TOTAL COMPREHENSIVE INCOME

—
—
319 $

(2)
(2)
244 $

(1)
(1)
241

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

137

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) provided by operating activities:

Equity in subsidiaries' earnings
Dividends from subsidiaries
Deferred and other income taxes
Net intercompany tax payments (to) from subsidiaries
Expense for the accelerated vesting of share-based awards associated with the Merger
Other
Changes in assets and liabilities, exclusive of changes shown separately:

Accounts receivable from subsidiaries
Income tax receivable
Prepaid and other current assets
Intercompany tax payable to subsidiaries
Accrued Compensation
Accrued taxes
Other current liabilities
Other non-current assets and liabilities, net

Net cash (used in) provided by operating activities

CASH FLOWS FROM INVESTING ACTIVITIES

Equity contributions to subsidiaries
Return of capital from subsidiaries
Other

Net cash provided by (used in) 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 agreement
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 agreements
Dividends on common stock
Dividends to ITC Investment Holdings Inc.
Issuance of common stock
Repurchase and retirement of common stock
Settlement of share-based compensation awards associated with the Merger — including

cost of accelerated share-based awards

Contribution from ITC Investment Holdings Inc. for the settlement of share-based awards

associated with the Merger

Other

Net cash provided by (used in) financing activities

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

CASH AND CASH EQUIVALENTS — Beginning of period

CASH AND CASH EQUIVALENTS — End of period

Year Ended December 31,
2016

2015

2017

319

246

242

(444)
3
67
(13)
—
5

(4)
2
(2)
(72)
14
—
(5)
8
(122)

(148)
296
(9)
139

999
97
200
(148)
(437)
(170)
(200)
—
(300)
—
—

—

(2)
39
56

(358)
10
(69)
(72)
41
25

22
(17)
1
85
(10)
(35)
3
5
(123)

(87)
274
(9)
178

399
126
—
48
(139)
(191)
(161)
(90)
(33)
13
(9)

(137)

137

(22)
(59)
(4)
8

(308)
185
(116)
121
—
21

3
—
—
—
1
9
3
(5)
156

(263)
161
(11)
(113)

—
839
—
95
—
(755)
—
(108)
—
14
(137)

—

11
(41)
2

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

138

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SCHEDULE I — Condensed Financial Information of Registrant

ITC HOLDINGS CORP.

NOTES TO CONDENSED FINANCIAL STATEMENTS (PARENT COMPANY ONLY)

1. GENERAL

For ITC Holdings Corp.’s (“ITC Holdings,” “we,” “our” and “us”) presentation (Parent Company only), the
investment in subsidiaries is accounted for using the equity method. The condensed parent company financial
statements and notes should be read in conjunction with the consolidated financial statements and notes of ITC
Holdings appearing in this Annual Report on Form 10-K.

As a holding company with no business operations, ITC Holdings’ assets consist primarily of investments in
our subsidiaries. ITC Holdings’ material cash inflows are only from dividends and other payments received from
our subsidiaries, the proceeds raised from the sale of debt securities, issuances under our commercial paper
program and borrowings under our revolving credit agreement. ITC Holdings may not be able to access cash
generated by our subsidiaries in order to fulfill cash commitments. The ability of our subsidiaries to make dividend
and other payments to us is subject to the availability of funds after taking into account their respective funding
requirements, the terms of their respective indebtedness, the regulations of the FERC under the FPA and applicable
state laws. In addition, there are practical limitations on using the net assets of each of our Regulated Operating
Subsidiaries as of December 31, 2017 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.

Supplementary Cash Flows Information

(In millions)
Supplementary cash flows information:

Interest paid
Income taxes paid (a)

Supplementary non-cash investing and financing activities:

Equity transfers to (from) subsidiaries

____________________________

Year Ended December 31,
2016

2015

2017

115 $
—

(2)

112 $

—

104
56

(a) Amount for the year ended December 31, 2016 does not include the income tax refund of $128 million received
from the Internal Revenue Service in August 2016, which resulted from the election of bonus depreciation as
described in Note 5 to the consolidated financial statements.

2. DEBT

As of December 31, 2017, the maturities of our debt outstanding were as follows:

(In millions)
2018
2019
2020
2021
2022
2023 and thereafter

Total

—
—
200
—
500
2,050
2,750

Refer to Note 9 to the consolidated financial statements for a description of the ITC Holdings Senior Notes, the

ITC Holdings Revolving Credit Agreements, the ITC Holdings Commercial Paper Program and related items.

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
$2,908 million and $2,297 million at December 31, 2017 and 2016, respectively. The total book value of the ITC

139

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Holdings Senior Notes, net of discount and deferred financing fees, was $2,728 million and $2,169 million at
December 31, 2017 and 2016, respectively. At December 31, 2017 we did not have anything outstanding under
our revolving and term loan credit agreements, which are variable rate loans compared to $73 million as of December
31, 2016. 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 in Note 12 to the consolidated financial statements. At December 31, 2017 ITC
Holdings did not have any commercial paper issued and outstanding under the commercial paper program
compared to $145 million as of December 31, 2016. Due to the short-term nature of these financial instruments,
the carrying value approximates fair value.

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, selling or otherwise disposing of all or substantially all of our assets and paying dividends.
In addition, the covenants require us to meet certain financial ratios, such as maintaining certain net debt to
capitalization ratios and certain funds from operations to net debt levels. At December 31, 2017, we were not in
violation of any debt covenant.

3. RELATED-PARTY TRANSACTIONS

Our related-party transactions during 2017, 2016 and 2015 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,
2016

2015

2017

148 $

87 $

296

274

4 $

(28) $

(35)

(14)

(34)

—

263

185

161

—

____________________________

(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.

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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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ITEM 16. FORM 10-K SUMMARY.

Not applicable.

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 14, 2018.

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 14, 2018

/s/ GRETCHEN L. HOLLOWAY
Gretchen L. Holloway

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

February 14, 2018

/s/ JOSEPH L. WELCH
Joseph L. Welch

/s/ ROBERT A. ELLIOTT
Robert A. Elliott

/s/ ALBERT ERNST
Albert Ernst

/s/ RHYS D. EVENDEN
Rhys D. Evenden

/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 14, 2018

Director

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February 14, 2018