ITC Annual Report 2016 | Quarterlytics

FY2016 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, 2016

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

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

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

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

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
(Do not check if a smaller reporting company)

Smaller Reporting Company

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, 2016 was approximately $7 billion,
based on the closing sale price as reported on the New York Stock Exchange. For purposes of this computation, all executive officers,
directors and 10% beneficial owners of the registrant are assumed to be affiliates. Such determination should not be deemed an admission
that such officers, directors and beneficial owners are, in fact, affiliates of the registrant.

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 16,
2017.

None

DOCUMENTS INCORPORATED BY REFERENCE

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ITC Holdings Corp.

Form 10-K for the Fiscal Year Ended December 31, 2016

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

Exhibits

Page
5

133

134

136

137

144

145

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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

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

Other definitions

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

Energy Corporation;

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

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

• “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;

• “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;

• “GIC” are references to GIC Private Limited;

• “ICC” are references to the Illinois Commerce Commission;

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

• “ISO” are references to Independent System Operators;

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

of Fortis;

• “IUB” are references to the Iowa Utilities Board;

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

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

• “kW” are references to kilowatts (one kilowatt equaling 1,000 watts);

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

• “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;

• “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;

• “MOPSC” are references to the Missouri Public Service Commission;

• “MPSC” are references to the Michigan Public Service Commission;

• “MPUC” are references to the Minnesota Public Utilities Commission;

• “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;

• “OCC” are references to Oklahoma Corporation Commission;

• “PSCW” are references to the Public Service Commission of Wisconsin;

• “RTO” are references to Regional Transmission Organizations;

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

• “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.

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.
In 2002, ITC Holdings was incorporated in the State of Michigan for the purpose of acquiring ITCTransmission.
ITCTransmission was originally formed in 2001 as a subsidiary of DTE Electric, an electric utility subsidiary of DTE
Energy, and was acquired in 2003 by ITC Holdings. METC was originally formed in 2001 as a subsidiary of
Consumers Energy, an electric and gas utility subsidiary of CMS Energy Corporation, and was acquired in 2006
by ITC Holdings. ITC Midwest was formed in 2007 by ITC Holdings to acquire the transmission assets of IP&L in
December 2007. ITC Great Plains was formed in 2006 by ITC Holdings and became a FERC-jurisdictional entity
in 2009. ITC Interconnection was formed in 2014 by ITC Holdings and became a FERC-jurisdictional entity in June
2016 after acquiring certain transmission assets from a merchant generating company and placing a newly
constructed transmission line in service. 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 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 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 a subsidiary of 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 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. For a discussion of various
risks relating to the Merger, see “Item 1A Risk Factors — Risks Relating to the Merger.” 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 continued investment in current transmission systems, generator
interconnections and our ongoing development projects. 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 2017 through 2021 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.

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Development Projects

Through our merchant and international activities, we are actively pursuing projects to upgrade the existing
transmission grid and regional transmission facilities, primarily to improve overall grid reliability, reduce transmission
constraints, enhance competitive markets and facilitate interconnections of new generating resources, including
wind generation and other renewable resources necessary to achieve state and federal policy goals. Additionally,
we may pursue other non-traditional transmission investment opportunities not described above.

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 16 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 Utility Lines Construction Services, Inc. (“ULCS”),
which is a division of Asplundh Tree Expert Co., to perform the majority of their maintenance. The agreement with
ULCS provides us with access to an experienced and scalable workforce with knowledge of our system at an
established rate.

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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 Local Balancing Authority (“LBA”) area, known as the Michigan
Electric Coordinated Systems (“MECS”). From our operations facility in Novi, Michigan, our employees perform
the LBA functions as outlined in MISO’s Balancing Authority Agreement. These functions include actual interchange
data administration and verification as well as MECS LBA area emergency procedure implementation and
coordination. ITC Midwest and ITC Great Plains 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 Master Operating Agreement (the “MOA”), dated as of February 28,
2003, governs the primary day-to-day operational responsibilities of ITCTransmission and DTE Electric and will
remain in effect until terminated by mutual agreement of the parties (subject to any required FERC approvals)
unless earlier terminated pursuant to its terms. The MOA identifies the control area coordination services that
ITCTransmission is obligated to provide to DTE Electric. The MOA also requires DTE Electric to provide certain
generation-based support services to ITCTransmission.

Generator Interconnection and Operation Agreement. DTE Electric and ITCTransmission entered into the
Generator Interconnection and Operation Agreement (the “GIOA”), dated as of February 28, 2003, in order to
establish, re-establish and maintain 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. Unless otherwise terminated by mutual agreement of the parties (subject to
any required FERC approvals), the GIOA will remain in effect until DTE Electric elects to terminate the agreement
with respect to a particular unit or until a particular unit ceases commercial operation.

Coordination and Interconnection Agreement. The Coordination and Interconnection Agreement (the
“CIA”), dated as of February 28, 2003, 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. The CIA will remain in effect until terminated by mutual agreement of the parties (subject to any
required FERC approvals).

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 Amended and Restated Easement Agreement
(the “Easement Agreement”), dated as of April 29, 2002 and as further supplemented, Consumers Energy
provides METC with an easement to the land, which we refer to as premises, on which a majority of METC’s
transmission towers, poles, lines and other transmission facilities used to transmit electricity at voltages of at
least 120 kV are located, which we refer to collectively as the facilities. Consumers Energy retained for itself

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the rights to, and the value of activities associated with, all other uses of the premises and the facilities covered
by the Easement Agreement, such as for distribution of electricity, fiber optics, telecommunications, gas pipelines
and agricultural uses. Accordingly, METC is not permitted to use the premises or the facilities covered by the
Easement Agreement for any purposes other than to provide electric transmission and related services, to
inspect, maintain, repair, replace and remove electric transmission facilities and to alter, improve, relocate and
construct additional electric transmission facilities. The easement is further subject to the rights of any third
parties that had rights to use or occupy the premises or the facilities prior to April 1, 2001 in a manner not
inconsistent with METC’s permitted uses.

METC pays Consumers Energy annual rent of $10 million, in equal quarterly installments, for the easement
and related rights under the Easement Agreement. Although METC and Consumers Energy share the use of
the premises and the facilities covered by the Easement Agreement, METC pays the entire amount of any
rentals, property taxes, inspection fees and other amounts required to be paid to third parties with respect to
any use, occupancy, operations or other activities on the premises or the facilities and is generally responsible
for the maintenance of the premises and the facilities used for electric transmission at its expense. METC also
must maintain commercial general liability insurance protecting METC and Consumers Energy against claims
for personal injury, death or property damage occurring on the premises or the facilities and pay for all insurance
premiums. METC is also responsible for patrolling the premises and the facilities by air at its expense at least
annually and to notify Consumers Energy of any unauthorized uses or encroachments discovered. METC must
indemnify Consumers Energy for all liabilities arising from the facilities covered by the Easement Agreement.

METC must notify Consumers Energy before altering, improving, relocating or constructing additional
transmission facilities covered by the Easement Agreement. Consumers Energy may respond by notifying
METC of reasonable work and design restrictions and precautions that are needed to avoid endangering existing
distribution facilities, pipelines or communications lines, in which case METC must comply with these restrictions
and precautions. METC has the right at its own expense to require Consumers Energy to remove and relocate
these facilities, but Consumers Energy may require payment in advance or the provision of reasonable security
for payment by METC prior to removing or relocating these facilities, and Consumers Energy need not commence
any relocation work until an alternative right-of-way satisfactory to Consumers Energy is obtained at METC’s
expense.

The term of the Easement Agreement runs through December 31, 2050 and is subject to 10 automatic 50-
year renewals after that time unless METC provides one year’s notice of its election not to renew the term.
Consumers Energy may terminate the Easement Agreement 30 days after giving notice of a failure by METC
to pay its quarterly installment if METC does not cure the non-payment within the 30-day notice period. At the
end of the term or upon any earlier termination of the Easement Agreement, the easement and related rights
terminate and the transmission facilities revert to Consumers Energy.

Amended and Restated Operating Agreement. Under the Amended and Restated Operating Agreement
(the “Operating Agreement”), dated as of April 29, 2002, METC agrees to operate its transmission system to
provide all transmission customers with safe, efficient, reliable and nondiscriminatory transmission service
pursuant to its tariff. Among other things, METC is responsible under the Operating Agreement 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. Consumers Energy has corresponding obligations to provide METC with access
to its books and records and to build distribution facilities necessary to provide adequate and reliable transmission
services to wholesale customers. Consumers Energy must cooperate with METC as METC performs its duties
as control area operator, including by providing reactive supply and voltage control from generation sources or
other ancillary services and reducing load. The Operating Agreement is effective through 2050 and is subject
to 10 automatic 50-year renewals after that time, unless METC provides one year’s notice of its election not to
renew.

Amended and Restated Purchase and Sale Agreement for Ancillary Services. The Amended and Restated
Purchase and Sale Agreement for Ancillary Services (the “Ancillary Services Agreement”) is dated as of April
29, 2002. 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

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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. METC is not precluded from procuring these ancillary services from third party suppliers when
available. The Ancillary Services Agreement is subject to rolling one-year renewals starting May 1, 2003, unless
terminated by either METC or Consumers Energy with six months prior written notice.

Amended and Restated Distribution-Transmission Interconnection Agreement. The Amended and Restated
Distribution-Transmission Interconnection Agreement (the “DT Interconnection Agreement”), dated April 1, 2001
and most recently amended and restated effective as of January 1, 2015, 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. METC agrees to provide Consumers Energy interconnection service at agreed-
upon interconnection points, and the parties have mutual responsibility for maintaining voltage and
compensating for reactive power losses resulting from their respective services. The DT Interconnection
Agreement is effective so long as any interconnection point is connected to METC, unless it is terminated earlier
by mutual agreement of METC and Consumers Energy.

Amended and Restated Generator Interconnection Agreement. The Amended and Restated Generator
Interconnection Agreement (the “Generator Interconnection Agreement”), dated as of April 29, 2002 and most
recently amended effective as of October 1, 2016, 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. The Generator Interconnection Agreement is effective either until it is replaced by any
MISO-required contract, or until mutually agreed by METC and Consumers Energy to terminate, but not later
than the date that all listed generators cease commercial operation.

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 Distribution-Transmission Interconnection
Agreement (the “DTIA”), dated as of December 17, 2007 and amended and restated effective as of December
1, 2016, 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. Additionally, the DTIA sets forth the terms pursuant to which the equipment
and facilities and the interconnection equipment of IP&L will continue to connect ITC Midwest’s facilities through
which ITC Midwest provides transmission service under the MISO Open Access Transmission, Energy and
Operating Reserve Markets Tariff. The DTIA will remain in effect until terminated by mutual agreement by the
parties (subject to any required FERC approvals) or as long as any interconnection point of IP&L is connected
to ITC Midwest’s facilities, unless modified by written agreement of the parties.

Large Generator Interconnection Agreement. ITC Midwest, IP&L and MISO entered into the Large
Generator Interconnection Agreement (the “LGIA”), dated as of December 20, 2007 and amended as of August
6, 2013, 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. The LGIA will remain in effect until terminated by ITC Midwest or until
IP&L elects to terminate the agreement if a particular unit ceases commercial operation for three consecutive
years.

Operations Services Agreement For 34.5 kV Transmission Facilities. ITC Midwest and IP&L entered into
the Operations Services Agreement for 34.5 kV Transmission Facilities (the “OSA”), effective as of January 1,
2011, 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. The
OSA will remain in full force and effect until December 31, 2015 and will extend automatically from year to year
thereafter until terminated by either party upon not less than one year prior written notice to the other party.

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ITC Great Plains

Amended and Restated Maintenance Agreement. Mid-Kansas Electric Company LLC (“Mid-Kansas”) and
ITC Great Plains have entered into a Maintenance Agreement (the “Mid-Kansas Agreement”), dated as of August
24, 2010, and most recently amended effective as of June 1, 2015, pursuant to which Mid-Kansas has agreed
to perform various field operations and maintenance services related to certain ITC Great Plains facilities. The
Mid-Kansas Agreement has an initial term of 10 years and automatic 10-year renewals unless terminated (1)
due to a breach by the non-terminating party following notice and failure to cure, (2) by mutual consent of the
parties, or (3) by ITC Great Plains under certain limited circumstances. Services must continue to be provided
for at least six months subsequent to the termination date in any case.

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 Department of Energy (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 transmission owner (“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 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 transmission owners 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 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.

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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.

FERC Order No. 1000 (“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. We are currently 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
recovery under their tariffs. Separate calculations of revenue requirement are performed for projects that have
been approved for regional cost sharing and impact only which parties ultimately pay for the transmission services
related to these projects and do not impact our financial results.

We have projects that are eligible for regional cost sharing under the MISO tariff, such as certain network
upgrade projects, and the MVPs, including the four North Central 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 two regional cost sharing projects in Kansas. Certain of these projects are described in more detail
in “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Recent
Developments.”

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 MPSC 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.

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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 IUB 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 IUB is vested with the power of condemnation in Iowa to the extent the IUB 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 MPUC 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 MPUC in conjunction with the Department of Commerce and certain local
authorities for compliance with applicable environmental standards and regulations.

Illinois

The ICC 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.

ITC Midwest also is 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 MOPSC has
jurisdiction to determine whether ITC Midwest may operate in such capacity. The MOPSC 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 PSCW 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 PSCW also recognized ITC Holdings Corp. as a public utility holding company under Wisconsin
statutes.

The PSCW 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

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

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

Oklahoma

ITC Great Plains has approval from the OCC to operate in Oklahoma, pursuant to Oklahoma Statutes as an
electric public utility providing only transmission services. The OCC 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.

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 20.7%, 21.7% and 25.5%, respectively, of our consolidated billed revenues for the year ended
December 31, 2016. 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 2014 revenue accruals and deferrals and exclude any amounts for the
2016 revenue accruals and deferrals that were included in our 2016 operating revenues, but will not be billed to
our customers until 2018. 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.

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Billing

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

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

credit policies.

Competition

Each of our MISO Regulated Operating Subsidiaries operates the primary transmission system in its respective
service area and has limited competition for certain projects. 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. Because our Regulated Operating Subsidiaries are currently the only transmission companies
that are independent from electricity market participants, we believe that we are best able to develop these projects
in a non-discriminatory manner. However, there are no assurances that we will be selected to develop projects
other entities are also pursuing.

Employees

As of December 31, 2016, we had 660 employees. We consider our relations with our employees to be good.

Environmental Matters

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

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Claims have been made or threatened against electric utilities for bodily injury, disease or other damages
allegedly related to exposure to electromagnetic fields associated with electric transmission and distribution lines.
While we do not believe that a causal link between electromagnetic field exposure and injury has been generally
established and accepted in the scientific community, the liabilities and costs imposed on our business could be
significant if such a relationship is established or accepted. We are not aware of any pending or threatened claims
against us for bodily injury, disease or other damages allegedly related to exposure to electromagnetic fields and
electric transmission and distribution lines that entail costs likely to have a material adverse effect on our results
of operations, financial position or liquidity.

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 Securities Exchange Act of 1934, as amended (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 Securities and Exchange Commission (the “SEC”). Our website also has posted our
Code of Conduct and Ethics. The information on our website is not incorporated by reference into this report.

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 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 targeted capital structures, are subject to challenge by interested
parties at the FERC, or by the FERC on its own initiative in a proceeding under Section 206 of the FPA. In addition,
interested parties may challenge the annual implementation and calculation by our Regulated Operating
Subsidiaries of their projected rates and formula rate true up pursuant to their approved formula rates under the
Regulated Operating Subsidiaries' formula rate implementation protocols. End-use consumers and entities
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, certain parties filed a joint complaint 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. The joint complainants sought a FERC order reducing
the base rate of return on equity used in the MISO transmission owners’ formula transmission rate, reducing the
targeted equity component of MISO transmission owners’ capital structures and terminating the return on equity
adders approved for ITCTransmission and METC. Although the FERC issued an order rejecting the November

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2013 complaint as to the capital structures and ITCTransmission's and METC’s equity adders, a hearing was
ordered on the November 2013 complaint's allegations as to the base rate of return on equity for all MISO
transmission owners. On December 22, 2015, the presiding administrative law judge issued an initial decision
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%. On September 28, 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.

In February 2015, an additional complaint was filed under Section 206 of the FPA seeking a FERC order reducing
the base rate of return on equity for all MISO transmission owners, including for our MISO Regulated Operating
Subsidiaries, to 8.67%. On June 30, 2016, the presiding administrative law judge issued an initial decision on the
February 2015 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 February 2015 complaint, with a maximum rate of 10.68%. In resolving the February 2015
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 going forward from the date on which the FERC issues an order. A decision from the FERC on the
February 2015 complaint is anticipated in 2017. In 2016, 2015 and 2014, 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 net income for those periods. The resolution of the second complaint may reduce our future revenues
and net income and have an adverse effect on our future results of operations, cash flows and financial condition.

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 invest in strategic development opportunities to
improve the efficiency and reliability of the transmission grid, but we cannot provide assurance that we
will be able to initiate or complete any of these investments. 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 to be lower than
anticipated.

We are pursuing broader strategic development investment opportunities including those related to building
regional transmission facilities and interconnections for generating resources, among others. Incumbent utilities
or other transmission development entities may compete with us for regulatory approval to develop capital projects
that we are pursuing. If we are unable to compete successfully for approval of these projects, our opportunities to
expand our rate base and increase our revenues and earnings may become limited.

Any capital investment at our operating subsidiaries or as a result of our broader strategic development initiatives
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. Therefore,
we can provide no assurance as to the actual level of investment we may achieve at our operating subsidiaries or
as a result of the broader strategic development initiatives.

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In addition, we expect to incur expenses to pursue strategic development investment opportunities. If these
expenses are higher than anticipated, our future results of operations, cash flows and financial condition could be
materially and adversely affected.

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

Each of our Regulated Operating Subsidiaries is a “public utility” under the FPA and, accordingly, is subject to
regulation by the FERC. Approval of the FERC is required under Section 203 of the FPA for a disposition or
acquisition of regulated public utility facilities, either directly or indirectly through a holding company. Such approval
is also required to acquire a significant interest in securities of a public utility. Section 203 of the FPA also provides
the FERC with explicit authority over utility holding companies’ purchases or acquisitions of, and mergers or
consolidations with, a public utility. Finally, each of our Regulated Operating Subsidiaries must also seek approval
by the FERC under Section 204 of the FPA for issuances of its securities (including debt securities).

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.

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
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.

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

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 57.3% of ITCTransmission’s total billed
revenues for the year ended December 31, 2016 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 76.7% of METC’s total billed revenues for the year ended December 31, 2016 and is expected to
constitute the majority of METC’s revenues for the foreseeable future. Consumers Energy is rated BBB+/stable
and A3/stable by Standard and Poor’s Ratings Services and Moody’s Investors Services, Inc., respectively. Further,
IP&L accounted for approximately 73.3% of ITC Midwest’s total billed revenues for the year ended December 31,
2016 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 2014 revenue accruals and deferrals and exclude any amounts for the 2016 revenue accruals and
deferrals that were included in our 2016 operating revenues, but will not be billed to our customers until 2018.

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 an Easement Agreement with Consumers Energy, METC pays annual rent of $10 million
to Consumers Energy in exchange for rights-of-way, leases, fee interests and licenses which allow METC to use
the land on which its transmission lines are located. Under the terms of the Easement Agreement, METC’s easement
rights could be eliminated if METC fails to meet certain requirements, such as paying contractual rent to Consumers
Energy in a timely manner. Additionally, a significant amount of the land on which our other subsidiaries’ assets
are located is subject to easements, mineral rights and other similar encumbrances. As a result, they must comply
with the provisions of various easements, mineral rights and other similar encumbrances, which may adversely
impact their ability to complete their construction projects in a timely manner.

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

We enter into various agreements and arrangements with third parties to provide services for construction,
maintenance and operations of certain aspects of our business, 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
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 and the
imposition of civil or criminal penalties. 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.

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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.

In addition, claims have been made or threatened against electric utilities for bodily injury, disease or other
damages allegedly related to exposure to electromagnetic fields associated with electric transmission and
distribution lines. We cannot provide assurance that such claims will not be asserted against us or that, if determined
in a manner adverse to our interests, such claims would not have a material effect on our business, financial
condition and results of operations.

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

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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.

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. The Trump
Administration has made federal corporate tax reform one of its priorities and the possibility of such reform is
thought to be increased in light of the Republican-led Congress. While such reform is likely to be favorable to
corporations generally, the structure of any such reform is unknown and a change in tax laws or rates could in fact
adversely affect our results of operations, net income, financial condition and cash flows. For example, federal
bonus depreciation is currently available for property acquired and placed in service through 2019, with certain
provisions that allow for an additional year of eligibility for certain property with long construction periods. If tax
reform results in extending accelerated tax depreciation similar to the provisions of bonus depreciation, the higher
deferred tax liabilities and the corresponding reduced rate base would have a negative effect on our annual revenues
and net income over the tax lives of the eligible assets. Additionally, we have a considerable amount of debt,
including debt at ITC Holdings, and any change in tax laws or regulations that reduce the deduction of interest
expense for income tax purposes could have a negative effect on our net income. We cannot predict the timing
or structure of tax-related developments.

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 are dividends and other payments received
by us from time to time from our subsidiaries, 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.

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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 credit agreements and commercial paper, that we rely on as
sources of capital and liquidity. This financing strategy 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 the funds available for working capital and capital expenditures.

• 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 risks described above.

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 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.

Our debt instruments also require us to meet certain financial ratios, such as maintaining certain debt to
capitalization ratios. 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.

Adverse changes in our credit ratings may negatively affect us.

Our ability to access capital markets is important to our ability to operate our business. Increased scrutiny of
the energy industry and the impact of regulation, as well as changes in our financial performance and unfavorable

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conditions in the capital markets could result in credit agencies reexamining our credit ratings. 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 credit agreements.

Risks Related to the Merger

ITC Holdings and its subsidiaries are subject to business uncertainties during the period of integration
with Fortis that could adversely affect ITC Holdings’ financial results.

Uncertainty about the effect of the Merger on employees or vendors and others, including contractors, may
have an adverse effect on us. These uncertainties may impair our ability to attract, retain and motivate key personnel,
and could cause vendors, contractors and others that deal with us to seek to change existing business relationships.
Employee retention may be challenging, as employees may experience uncertainty about their future roles with
the combined company. If, despite our retention efforts, key employees retire or depart due to the uncertainty of
employment and difficulty of integration or a desire not to remain with the combined company, we may incur
significant costs in identifying, hiring, and retaining replacements for departing employees, which could have a
material adverse effect on our business operations and financial results. In addition, integration-related issues may
place a significant burden on management, employees and internal resources which could otherwise have been
devoted to other business opportunities. The diversion of management’s attention and any delays or difficulties
encountered in connection with the Merger and the integration of ITC Holdings’ operations with Fortis could have
an adverse effect on our business, financial results or financial condition. The integration process may also result
in additional and unforeseen expenses.

We are the target of securities class action and derivative lawsuits, which could result in substantial
costs and diversion of management’s time and resources.

Securities class action lawsuits and derivative lawsuits are often brought against companies that have entered
into merger agreements. There is currently a class action lawsuit pending against us and our directors in connection
with the Merger, as described in Note 15 to the consolidated financial statements. We are not able to predict the
outcome of this action or others that may be brought, nor can we predict the amount of time and expense that will
be required to resolve the actions. Even if we believe the lawsuits are without merit, defending against or settling
these claims can result in substantial costs to us and divert management’s time and resources.

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 14 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 185 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;

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• an approximately 188,000 square-foot corporate headquarters facility and operations control room in Novi,

Michigan, including furniture, fixtures and office equipment; and

• 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 37,000 transmission towers and poles;

• station assets, such as transformers and circuit breakers, at 104 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 its
Easement Agreement with Consumers Energy, 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 276 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 1,910 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.

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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.

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, 2016, 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 15 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 full quarterly period in 2015 and 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

Year Ended December 31, 2015
Quarter ended December 31, 2015
Quarter ended September 30, 2015
Quarter ended June 30, 2015
Quarter ended March 31, 2015

High
46.48
47.46
46.89
43.89

High
39.60
35.68
37.12
44.00

Low
44.91
44.64
42.44
36.53

Low
30.33
31.16
30.64
35.54

Dividends
—
0.2155
0.1875
0.1875

Dividends
$ 0.1875
0.1875
0.1625
0.1625

Additionally, ITC Holdings paid dividends of $33 million to Investment Holdings during the fourth quarter of 2016.
ITC Holdings also paid dividends of $33 million to Investment Holdings in January 2017. 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.

There were no share repurchases for the period from October 1, 2016 through the closing of the Merger.

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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) (b) (c)
OPERATING EXPENSES

Operation and maintenance

General and administrative (d) (e) (f)

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
Loss on extinguishment of debt

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) (g)

Property, plant and equipment — net

Goodwill

Total assets (g) (h)

Debt:

ITC Holdings (h)
Regulated Operating Subsidiaries (h)

Total debt (h)
Total stockholders’ equity

(In millions)
CASH FLOWS DATA:

Expenditures for property, plant and

equipment

____________________________

2016

ITC Holdings and Subsidiaries
Year Ended December 31,
2014

2015

2013

2012

1,125

1,045

1,023

941

831

114

239

158

(1)
603
522

211

(35)

—

(2)
5
179
343
97
246

2016

113

145

(1)
484
561

204

(28)

—

(2)
3
177
384
142
242

112

115

128

(1)
430
593

187

(21)

(1)
5
199
394
150
244

113

149

119

(2)
445
496

168

(30)

—

(1)
7
144
352
119
233

ITC Holdings and Subsidiaries
As of December 31,
2014

2015

2013

122

112

107

(2)
399
432

156

(23)

—

(2)
4
135
297
109
188

2012

8 $

14 $

28 $

34 $

(400)
6,698
950
8,223

(550)
6,110
950
7,555

(291)
5,497
950
6,932

(325)
4,847
950
6,241

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

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

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

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

2016

ITC Holdings and Subsidiaries
Year Ended December 31,
2014

2015

2013

26
(828)
4,135
950
5,525

1,683
1,448
3,131
1,415

2012

750 $

701 $

753 $

824 $

814

(a) During 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 15 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, respectively.

(b) During 2015, we recognized a regulatory liability for the refund relating to the formula rate template modifications
filing as described in Note 5 to the consolidated financial statements, which resulted in a reduction in operating
revenues of $10 million.

revenues of $11 million.

(d) 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.

(e) The increase in general and administrative expenses in 2015 was due primarily to higher compensation related
expenses, including the development bonuses described below under “Recent Developments — Development
Bonuses,” and higher legal and advisory professional service fees for various development initiatives.

(f) During 2013 and 2012, we expensed external legal, advisory and financial services fees of $43 million and
$19 million, respectively, 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.

(g) 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.

(h) 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 2016. Refer to Notes 3 and 9 of the
consolidated financial statements for more information.

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, expectations with respect to various legal and regulatory
proceedings and the Merger 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.

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Overview

Through our Regulated Operating Subsidiaries, we operate high-voltage systems in Michigan 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 operate, maintain and invest in
transmission infrastructure in order to enhance system integrity and reliability, reduce transmission constraints and
upgrade the transmission networks to support new generating resources interconnecting to our transmission
systems. We also are pursuing development projects not within our existing systems, which are likewise 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 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 in “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’ 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, 2016 or that may affect future results include:

• Our capital expenditures of $750 million at our Regulated Operating Subsidiaries during the year ended
December 31, 2016, resulting primarily from our focus on improving system reliability, increasing system
capacity and upgrading the transmission network to support new generating resources;

• Debt issuances as described in Note 9 to the consolidated financial statements, including commercial paper
issued under ITC Holdings’ commercial paper program, and borrowings under our revolving and term loan
credit agreements in 2016 and 2015 to fund capital investment at our Regulated Operating Subsidiaries as
well as for general corporate purposes;

• Debt maturing within one year of $235 million 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;

• Recognition of the liability for the refund and potential refund relating to the rate of return on equity (“ROE”)
complaints, as described in Note 15 to the consolidated financial statements, which resulted in a total
estimated pre-tax reduction of revenue and additional interest of $90 million and $120 million and an estimated
after-tax reduction to net income of $55 million and $73 million for the years ended December 31, 2016 and
2015, respectively. On February 14, 2017, our MISO Regulated Operating Subsidiaries provided $119 million
to MISO to fund the payment of the refund, including interest, for the initial ROE complaint;

• Election of bonus depreciation for tax years 2015 and 2016. The total impact from these matters was lower
revenues of approximately $20 million and lower net income of approximately $12 million for the year ended
December 31, 2016. These matters also resulted in additional net deferred income tax liabilities of
approximately $109 million and a corresponding income tax receivable of $12 million as of December 31,
2016, and income tax refunds of $128 million, which were received in August 2016; and

• As a result of the Merger consummated on October 14, 2016, ITC Holdings became an indirect subsidiary
of Fortis as described below under “Recent Developments — The Merger.” For the year ended December
31, 2016, we expensed external legal, advisory and financial services fees related to the Merger of $55
million and certain internal labor and associated costs related to the Merger of approximately $58 million,
including approximately $41 million of expense recognized due to the accelerated vesting of the share-based
awards described in Note 13 to the consolidated financial statements. These merger-related costs were

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recorded within general and administrative expenses. Certain amounts of the external costs are not expected
to be deductible for income tax purposes. 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.

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
and 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 rates, each of our Regulated Operating Subsidiaries separately
calculates a revenue requirement based on financial information specific to each company. The calculation of
projected revenue requirement for a future period is used to establish the transmission rate used for billing purposes.
The calculation of actual revenue requirements for a historic period is used to calculate the amount of revenues
recognized in that period and determine the over- or under-collection for that period.

Under these formula rates, our Regulated Operating Subsidiaries recover expenses and earn a return on and
recover investments in property, plant and equipment on a current basis, rather than lagging. The formula rate for
a given year initially utilizes 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.

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.

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(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
15 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.

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 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 15 to the consolidated
financial statements. 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.
In addition, 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. 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.

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

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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:

Actual Capital

Forecasted

Expenditures for the

Capital

year ended

Expenditures

(In millions)

Expenditures for property, plant and equipment (a)

____________________________

December 31, 2016
$

750 $

2017 — 2021
2,812

(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 do not include 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.

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

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

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 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 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.

ITC Interconnection

ITC Interconnection was formed in 2014 by ITC Holdings to pursue transmission investment opportunities. On
June 1, 2016, ITC Interconnection acquired certain transmission assets from a merchant generating company and
placed a newly constructed 345 kV transmission line in service. As a result, ITC Interconnection became a
transmission owner in the FERC-approved RTO, PJM Interconnection, 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. The financial results of ITC Interconnection are currently not material to our
consolidated financial statements.

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Development Bonuses

During 2016, 2015 and 2014, we recognized general and administrative expenses of $1 million, $11 million and
$3 million, respectively, for bonuses for certain development projects, including the successful completion of certain
milestones relating to projects at ITC Great Plains.

Rate of Return on Equity Complaints

On November 12, 2013, certain parties (the “complainants”) filed a joint complaint with the FERC under Section
206 of the FPA (the “Initial Complaint”), requesting that the FERC find the then current 12.38% MISO regional base
ROE rate (the “base ROE”) 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 to 9.15%, reducing the equity component of
our capital structure from the FERC approved 60% to 50% and terminating the ROE adders approved for certain
ITC Holdings Regulated Operating Subsidiaries, including adders currently utilized by ITCTransmission and METC.

On October 16, 2014, the FERC granted the complainants’ request in part by setting the base ROE for hearing
and settlement procedures, while denying all other aspects of the Initial Complaint. The FERC also denied the
request to terminate ITCTransmission’s and METC’s ROE incentives, subject to the top end of a zone of
reasonableness. The FERC set the refund effective date for the Initial Complaint as November 12, 2013.

On December 22, 2015, the presiding administrative law judge issued an initial decision on the Initial Complaint.
On September 28, 2016, the FERC issued an order (the “September 2016 Order”) affirming the presiding
administrative law judge’s initial decision and setting the base ROE at 10.32%, with a maximum ROE of 11.35%,
effective for the period from November 12, 2013 through February 11, 2015 (the “Initial Refund Period”). Additionally,
the rates established by the September 2016 Order will be used prospectively from the date of that order until a
new approved rate is established by the FERC in ruling on the Second Complaint described below, resulting in an
ROE used currently by ITCTransmission, METC and ITC Midwest of 11.35%, 11.35% and 11.32%, respectively.
The September 2016 Order requires all MISO TOs, including our MISO Regulated Operating Subsidiaries, to
provide refunds within 30 days for the Initial Refund Period. The estimated refund for the Initial Complaint resulting
from this FERC order, including interest, is $118 million for our MISO Regulated Operating Subsidiaries, recorded
in current liabilities on the consolidated statements of financial position. On October 21, 2016, the MISO TOs,
including our MISO Regulated Operating Subsidiaries, filed a request with the FERC for an extension of nine
months, until July 28, 2017, to provide refunds, which was granted by the FERC on October 28, 2016. Additionally,
on October 28, 2016, the MISO TOs, including our MISO Regulated Operating Subsidiaries, filed a request with
the FERC for rehearing of the September 2016 Order regarding the future exclusion of certain short-term growth
projections in the two-step DCF analysis used by FERC to determine the cost of equity of public utilities. On October
28, 2016, the complainants also filed a request with the FERC for rehearing, citing that FERC erred in several
material respects in the September 2016 Order. The FERC issued a tolling order on November 28, 2016 to allow
for additional time to address the rehearing requests. On February 14, 2017, our MISO Regulated Operating
Subsidiaries provided $119 million to MISO to fund the payment of the refund, including interest, pursuant to the
September 2016 Order.

On February 12, 2015, an additional complaint was filed with the FERC under Section 206 of the FPA (the
“Second Complaint”) by separate complainants, seeking a FERC order to reduce the base ROE used in the formula
transmission rates of our MISO Regulated Operating Subsidiaries to 8.67%, with an effective date of February 12,
2015. On June 18, 2015, the FERC set the Second Complaint for hearing and settlement procedures. The FERC
also set the refund effective date for the Second Complaint as February 12, 2015.

On June 30, 2016, the presiding administrative law judge issued an initial decision on the Second Complaint,
which recommended a base ROE of 9.70% for February 12, 2015 through May 11, 2016 (the “Second Refund
Period”), with a maximum ROE of 10.68%. The initial decision is a non-binding recommendation to the FERC on
the Second Complaint, and all parties, including the MISO TOs and the complainants, have filed briefs contesting
various parts of the proposed findings and recommendations. In resolving the Second Complaint, we expect the
FERC to establish a new base ROE and zone of reasonable returns that will be used, along with any ROE adders,
to calculate the refund liability for the Second Refund Period. We anticipate a FERC order on the Second Complaint
in 2017. The timing of providing refunds for the Second Complaint is uncertain; however, we do not expect to
provide refunds during 2017 for the Second Complaint and therefore, the associated refund liability is recorded in
non-current liabilities on the consolidated statements of financial position.

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In addition to the estimated refund for the Initial Complaint noted above, we believe it is probable that a refund
will be required in connection with the Second Complaint. As of December 31, 2016, the estimated range of
aggregate refunds for the Initial Refund Period and Second Refund Period is expected to be from $221 million to
$258 million on a pre-tax basis. As of December 31, 2016, our MISO Regulated Operating Subsidiaries had recorded
aggregate estimated regulatory liabilities totaling $258 million for the Initial Complaint and Second Complaint,
representing the best estimate of the probable aggregate refunds based on the resolution of the Initial Complaint
in the September 2016 Order. As of December 31, 2015, our MISO Regulated Operating Subsidiaries had recorded
an aggregate estimated regulatory liability of $168 million, which represented the low end of the range of potential
refunds as of that date, as there was no best estimate within the range of refunds at that time. The recognition of
these estimated liabilities resulted in the following impacts to our consolidated results of operations:

(In millions)
Increase (decrease) in:
Operating revenues
Interest expense
Estimated net income

Year Ended December 31,
2015

2016

2014

(80) $
10
(55)

(115) $
5
(73)

(47)
1
(29)

It is possible 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 under the newly adopted two-step DCF methodology, which is subject to significant
discretion by the FERC. As of December 31, 2016, our MISO Regulated Operating Subsidiaries had a total of
approximately $3 billion of equity in their collective capital structures for ratemaking purposes. Based on this level
of aggregate equity, we estimate that each 10 basis point reduction in the authorized ROE would reduce annual
consolidated net income by approximately $3 million.

In a separate but related matter, in November 2014, METC, ITC Midwest and other MISO TOs filed a request
with the FERC, under FPA Section 205, for authority to include a 50 basis point incentive adder for RTO participation
in each of the TOs’ formula rates. On January 5, 2015, the FERC approved the use of this incentive adder, effective
January 6, 2015. Additionally, ITC Midwest filed a request with the FERC, under FPA Section 205, in January 2015
for authority to include a 100 basis point incentive adder for independent transmission ownership, which is currently
authorized for ITCTransmission and METC. On March 31, 2015, the FERC approved the use of a 50 basis point
incentive adder for independence, effective April 1, 2015. On April 30, 2015, ITC Midwest filed a request with the
FERC for rehearing on the approved incentive adder for independence and this request was subsequently denied
by the FERC on January 6, 2016. An appeal of the FERC’s decision has been filed. Beginning September 28,
2016, these incentive adders have been applied to METC’s and ITC Midwest’s base ROEs in establishing their
total authorized ROE rates, subject to the maximum ROE limitation in the September 2016 Order of 11.35%.

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 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 the recovery of excess amounts from customers. As of December 31,
2016 and 2015, our MISO Regulated Operating Subsidiaries had recorded an aggregate refund liability of $2 million
and $10 million, respectively. The initial recognition of this refund liability in 2015 resulted in a reduction to operating
revenues and an increase to interest expense during the year ended December 31, 2015.

Challenges Regarding Bonus Depreciation

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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. The FERC denied IP&L’s request
that ITC Midwest be required to elect bonus depreciation in any past or future years; however, stakeholders will
be able to challenge any decision by ITC Midwest not to take bonus depreciation in future years. 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 resolution of a private letter ruling matter from the IRS. In a separate but related matter, on April 15,
2016, Consumers Energy filed a formal challenge, or in the alternative, a complaint under Section 206 of the FPA,
with the FERC against METC relating to METC’s historical practice of opting out of using bonus depreciation. On
July 8, 2016, the FERC denied Consumers Energy’s formal challenge and dismissed the complaint without
prejudice.

The consolidated financial statements reflect the election of bonus depreciation for tax years 2015 and 2016
and the corresponding effects on 2016 revenue requirements for our Regulated Operating Subsidiaries. Additionally,
as required by the March 11, 2016 FERC order, we have simulated the election of bonus depreciation for ITC
Midwest’s 2015 revenue requirement and included the impact of the corresponding refund obligation in these
consolidated financial statements. The total impact from reflecting the election of bonus depreciation as described
above was lower revenues of $20 million and lower net income of approximately $12 million for the year ended
December 31, 2016 as compared to the same period if bonus depreciation was not reflected. These matters also
resulted in additional net deferred income tax liabilities of approximately $109 million and a corresponding income
tax receivable of $12 million as of December 31, 2016, and income tax refunds of $128 million, which were received
from the Internal Revenue Service (“IRS”) in August 2016. We are unable to predict the final outcome of this matter;
however, the election of bonus depreciation will result in higher cash flows in the year of the election and/or
subsequent periods, and reduce our rate base and therefore decrease our revenues and net income over the tax
lives of the eligible assets. Bonus depreciation is currently available for property acquired and placed in service
through 2019, with certain provisions that allow for an additional year of eligibility for certain property with long
construction periods. If bonus depreciation is elected for a given year, we estimate that, based on an amount of
tax additions that may be eligible for bonus depreciation representative of our investment plans in the near term,
the higher deferred tax liabilities and the corresponding reduced rate base could reduce revenues recognized by
us initially for that year by $15 million to $20 million, with a corresponding reduction to annual net income of $9
million to $12 million (disregarding any favorable effects from the use of the potential cash tax savings), with the
negative effect on annual revenues and net income relating to each year’s election decreasing each year over the
tax lives of the assets.

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.

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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 the four North Central 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.

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 is 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 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.

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

Income Tax Provision

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

Results of Operations

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

(In millions)
OPERATING REVENUES

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

Loss on extinguishment of debt

Other income

Other expense

Total other expenses (income)

INCOME BEFORE INCOME TAXES

INCOME TAX PROVISION

Year Ended
December 31,

2016

2015

Increase
(Decrease)

Percentage
Increase
(Decrease)

Year Ended
December 31,
2014

Increase
(Decrease)

Percentage
Increase
(Decrease)

1,125

1,045

114

239

158

(1)

603

522

211

(35)

—

(2)

179

343

—

119

(39)

(7)

—

(41)

(45)

1,023

65%

13%

—%

25%

(7)%

25%

n/a

—%

67%

(11)%

(32)%

112

115

128

(1)

430

593

187

(21)

(1)

5
199

394

150

244

—

(32)

26%

13%

—%

13%

(5)%

(7)

(29)

(1)

(2)
(22)

(10)

(8)

(2)

33%

(100)%

100%

(40)%

(11)%

(3)%

(5)%

(1)%

113

145

(1)

484

561

204

(28)

—

(2)

177

384

142

242

NET INCOME

246

Operating Revenues

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.

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The recognition of the liabilities for the refund relating to the formula rate template modifications and the refund
and potential refund relating to the ROE complaints, described in Notes 5 and 15 to the consolidated financial
statements, respectively, resulted in a reduction to operating revenues of $80 million and $125 million 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.

Year ended December 31, 2015 compared to year ended December 31, 2014

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

2015

2014

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

802
328
15
13
12
(125)
1,045

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

764
265
18
12
11
(47)
1,023

Increase
(Decrease)
38
63
(3)
1
1
(78)
22

75 % $
26 %
2 %
1 %
1 %
(5)%
100 % $

Percentage
Increase
(Decrease)

5 %
24 %
(17)%
8 %
9 %
166 %
2 %

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, 2015
as compared to 2014. Higher net revenue requirements were due primarily to higher rate bases associated with
higher balances of property, plant and equipment in-service in 2015.

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, 2015 as compared to the same period in 2014. We expect to continue to receive regional cost sharing revenues
and the amounts could increase in the near future, including revenues associated with projects that have been or
are expected to be approved for regional cost sharing.

The recognition of the liabilities for the refund relating to the formula rate template modifications and the refund
and potential refund relating to the ROE complaints described in Notes 5 and 15 to the consolidated financial
statements, respectively, resulted in a reduction to operating revenues totaling $125 million and $47 million during
the years ended December 31, 2015 and 2014, 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, 2015 and 2014 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, 2016 and 2015 compared to year ended December 31, 2015 and 2014, respectively

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

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General and administrative expenses

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

General and administrative expenses increased $59 million related to higher compensation-related expenses
due to retention bonuses relating to the Merger, personnel additions and additional stock compensation expense,
including approximately $41 million due to the accelerated vesting of the share-based awards that occurred at the
completion of the Merger as described in Note 13 to the consolidated financial statements, and increased $55
million due primarily to the external legal, advisory and financial services fees incurred in 2016 related to the Merger.
These increases were partially offset by a decrease of $10 million in development bonus expenses as described
above under “Recent Developments — Development Bonuses.”

Year ended December 31, 2015 compared to year ended December 31, 2014

General and administrative expenses increased due primarily to higher compensation-related expenses of $17
million, mainly due to $8 million additional development bonuses described above under “Recent Developments
— Development Bonuses” and $10 million higher professional services such as legal and advisory services fees
primarily for various development initiatives.

Depreciation and amortization expenses

Year ended December 31, 2016 and 2015 compared to year ended December 31, 2015 and 2014, respectively

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, 2016 compared to year ended December 31, 2015

Taxes other than income taxes increased due to higher property tax expenses primarily due to our Regulated

Operating Subsidiaries’ 2015 capital additions, which are included in the assessments for 2016 property taxes.

Year ended December 31, 2015 compared to year ended December 31, 2014

Taxes other than income taxes increased due to higher property tax expenses primarily due to our Regulated

Operating Subsidiaries’ 2014 capital additions, which are included in the assessments for 2015 property taxes.

Other expenses (income)

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 15 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.

Year ended December 31, 2015 compared to year ended December 31, 2014

Interest expense increased due primarily to additional interest expense associated with the net issuance of
$300 million in long-term debt securities subsequent to September 30, 2014 and the refund liabilities described in
Notes 5 and 15 to the consolidated financial statements. These increases were partially offset by an increase in
the allowance for borrowed funds used during construction (“AFUDC debt”), which is a reduction to interest expense,
due primarily to higher balances of construction work in progress eligible for AFUDC debt during the period.

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

equity during the period.

The loss on extinguishment of debt represents the tender premium, the write-off of deferred debt issuance costs
and other related expenses associated with the partial tender and retirement in 2014 of $116 million of the 5.875%
ITC Holdings Senior Notes and $55 million of the 6.375% ITC Holdings Senior Notes.

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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 Notes 3 and 10. 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.

Year ended December 31, 2015 compared to year ended December 31, 2014

Our effective tax rates for the years ended December 31, 2015 and 2014 are 36.9% and 38.1%, respectively.
Our effective tax rate in both periods 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.

Liquidity and Capital Resources

We expect to maintain our approach to fund our future capital requirements with cash from operations at our
Regulated Operating Subsidiaries, our existing cash and cash equivalents, issuances under our commercial paper
program and amounts available under our revolving 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 transmission projects that will continue to result in the incurrence of development expenses and
could result in significant capital expenditures.

• 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 return on equity complaints.

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

statements. We expect to contribute up to $12 million to these plans in 2017.

In addition to the expected capital requirements above, any adverse determinations relating to the regulatory
matters or contingencies described in Notes 5 and 15 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.

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We expect to continue to utilize our commercial paper program and revolving credit agreements as well as our
cash and cash equivalents as needed to meet our short-term cash requirements. As of December 31, 2016, we
had consolidated indebtedness under our revolving credit agreements of $334 million, with unused capacity under
the revolving credit agreements of $666 million. Additionally, ITC Holdings had $145 million of commercial paper
issued and outstanding as of December 31, 2016, with the ability to issue an additional $255 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 credit agreements as well as the debt activity during the years ended
December 31, 2016 and 2015.

As of December 31, 2016, we had approximately $90 million of fixed rate debt maturing within one year and a
refund obligation of $118 million in connection with the September 2016 Order, which we expect to (1) repay with
either borrowings under our revolving credit agreements or commercial paper issued under ITC Holdings’
commercial paper program, or (2) 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)
BBB+
A-2
A
A
A
A

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

(a) On June 8, 2015, Standard and Poor’s Ratings Services (“Standard and Poor’s”) assigned a short-term issuer
credit rating to ITC Holdings, which applies to the commercial paper program discussed in Note 9 to the
consolidated financial statements. Additionally, on October 18, 2016, Standard and Poor’s reaffirmed the senior
unsecured credit rating of ITC Holdings and the secured credit ratings of our MISO Regulated Operating
Subsidiaries and ITC Great Plains as well as revised the outlook of the issuer credit ratings of these particular
entities to stable from negative, subsequent to the completion of the Merger. Refer to Note 2 to the consolidated
financial statements for details on the Merger.

(b) On June 9, 2015, Moody’s Investor Service, Inc. (“Moody’s”) assigned a short-term commercial paper rating
to ITC Holdings, which applies to the commercial paper program discussed in Note 9 to the consolidated
financial statements. Additionally, on April 15, 2016, Moody’s reaffirmed the credit ratings for the associated
debt for ITC Holdings, ITCTransmission, ITC Midwest and ITC Great Plains. On April 26, 2016, Moody’s
assigned a senior secured rating to METC’s 3.90% Senior Secured Note issuance described in Note 9 to the
consolidated financial statements. All of the credit ratings have a stable outlook.

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, 2016, 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 would 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 Investment Holdings
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
Contribution from Investment Holdings associated with the settlement of

share-based awards

Other

Net cash provided by financing activities

NET 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,
2015

2014

2016

246 $

242 $

244

158

(2)
219
66
687

(750)
15
(735)

161
13
(90)
(33)

23
(9)
(137)

137
(23)
42
(6)
14

8 $

145

(54)
77
146
556

(701)
1
(700)

352
14
(108)
—

1
(137)
—

—
8
130
(14)
28
14 $

128

(4)
90
44
502

(753)
18
(735)

463
21
(96)
—

(23)
(134)
—

—
(4)
227
(6)
34
28

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

Net cash provided by operating activities increased $131 million in 2016 compared to 2015. The increase in
cash provided by operating activities was due primarily to receipt of the federal income tax refund of $128 million
in August 2016 and lower income taxes paid of $33 million during 2016 compared to 2015, which both resulted
from the election of bonus depreciation as described in Note 5 to the consolidated financial statements. Additionally,
the cash received from operating revenues increased by $67 million during 2016 compared to 2015. These
increases were partially offset by an increase in payments of operating expenses of $54 million and the regional
cost allocation refund of $29 million provided by ITCTransmission to the relevant RTOs in October 2016 as described
in Note 5 to the consolidated financial statements.

Year ended December 31, 2015 compared to year ended December 31, 2014

Net cash provided by operating activities increased $54 million in 2015 compared to 2014. The increase in cash
provided by operating activities was due primarily to an increase in cash received from operating revenues of $70
million during 2015 compared to 2014. This increase was partially offset by an increase in payments of operating
expenses of $25 million.

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Cash Flows From Investing Activities

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

Net cash used in investing activities increased $35 million 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.

Year ended December 31, 2015 compared to year ended December 31, 2014

Net cash used in investing activities decreased $35 million in 2015 compared to 2014. The decrease 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, 2015 compared to the same period in 2014.

Cash Flows From Financing Activities

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

Net cash provided by financing activities decreased $88 million in 2016 compared to 2015. The decrease in
cash provided by financing activities was due primarily to a net decrease of $554 million in amounts outstanding
under our revolving and term loan credit agreements, the settlement of share-based awards associated with the
Merger of $137 million, a decrease of $47 million in net issuances of commercial paper under our commercial
paper program and an increase in dividend payments of $15 million during 2016 compared to 2015. These
decreases were partially offset by an increase in long-term debt issuances of $374 million, a capital contribution
from Investments Holdings of $137 million, a decrease in the repurchase and retirement of common stock of $128
million, a decrease in payments of $36 million to retire long-term debt and higher net proceeds of $22 million
associated with refundable deposits for transmission network upgrades. Additionally, during the year ended
December 31, 2015, we paid $115 million in connection with an accelerated share repurchase program. See Note
9 to the consolidated financial statements on the issuances and retirement of long-term debt.

Year ended December 31, 2015 compared to year ended December 31, 2014

Net cash provided by financing activities decreased $97 million in 2015 compared to 2014. The decrease in
cash provided by financing activities was due primarily to a decrease in long-term debt issuances of $574 million
during 2015 compared to 2014. This decrease was partially offset by a net increase of $245 million in amounts
outstanding under our revolving and term loan credit agreements, a decrease in payments of $124 million to retire
long-term debt, the $95 million in net proceeds from the issuance of commercial paper under our commercial paper
program during the year ended December 31, 2015 and lower net payments of $24 million 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, 2016:

Total

Due within
1 Year

Due in
Years 2-3

Due in
Years 4-5

Due after
5 years

2,185 $
73
145
585

50 $
—
145
—

44
475
31
750
127
150

1,033
593
547
736
174
5
44

—
—
—
40
—
—

—

103
29
20
32
6
1
43

385 $

73
—
100

44
—
31
—
127
—

157
49
40
66
12
2
1

—

200 $
—
—
—

1,550
—
—
485

—
—
—
35
—
—

—

133
47
40
63
13
2
—

—

—
475
—
675
—
150

—

640
468
447
575
143
—
—

—

(In millions)
Debt:

ITC Holdings Senior Notes

ITC Holdings revolving credit agreement

ITC Holdings commercial paper program

ITCTransmission First Mortgage Bonds
ITCTransmission revolving 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

Interest payments:

ITC Holdings Senior Notes

ITCTransmission First Mortgage Bonds

METC Senior Secured Notes

ITC Midwest First Mortgage Bonds

ITC Great Plains First Mortgage Bonds

Operating leases

Purchase obligations
Regulatory liabilities — revenue deferrals,

including accrued interest

Regulatory liabilities — refund related to the

formula rate template modifications,
including accrued interest

Regulatory liabilities — refund related to the

Initial Complaint, including accrued
interest

METC Easement Agreement
Other

Total obligations

118
339
1
8,257 $

118
10
1
609 $

—
20
—
1,198 $

—
20
—
553 $

—
289
—
5,897

Interest payments included above relate only to our fixed-rate long-term debt outstanding at December 31,
2016. We also expect to pay interest and commitment fees under our variable-rate revolving credit agreements
that have not been included above due to varying amounts of borrowings and interest rates under the facilities. In
2016, we paid $5 million of interest and commitment fees under our revolving 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, 2016, 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 15 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.

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See Notes 5 and 15 to the consolidated financial statements for information on the refund related to the formula
rate template modifications, including accrued interest, and the refund related to the Initial Complaint, including
accrued interest, respectively. On February 14, 2017, our MISO Regulated Operating Subsidiaries provided $119
million to MISO to fund the payment of the refund, including interest, pursuant to the September 2016 Order.

The Easement Agreement provides METC with an easement for transmission purposes and rights-of-way,
leasehold interests, fee interests and licenses associated with the land over which the transmission lines cross.
The cost for use of the rights-of-way is $10 million per year. The term of the Easement Agreement runs through
December 31, 2050 and is subject to 10 automatic 50-year renewals thereafter unless METC gives notice of
nonrenewal of at least one year in advance. Payments to Consumers Energy under the Easement Agreement are
charged to operation and maintenance expense.

The contractual obligations table above excludes certain items, including the estimated potential 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 accounting principles generally accepted
in the United States of America (“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 regulation by the FERC. As a result, we apply accounting
principles in accordance with the standards set forth by the Financial Accounting Standards Board (“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 $300 million and $378 million, respectively, as of December 31, 2016. 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 $43 million relating to
intangible assets at December 31, 2016 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, rather than lagging, 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

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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 under-recovery or over-recovery
of revenues, as appropriate. The under- or over-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, and 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
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. In order to perform these impairment
tests, we compare the fair value of each reporting unit with their respective carrying value. Our reporting units are
ITCTransmission, METC and ITC Midwest as each entity represents an individual operating segment to which
goodwill has been assigned. 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, 2016 and 2015, consolidated goodwill totaled $950 million. We completed our annual
goodwill impairment test for our reporting units as of October 1, 2016 using a qualitative assessment and determined
that no impairment exists. There were no events subsequent to October 1, 2016, including the Merger consummated
on October 14, 2016, 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 in accordance with GAAP. 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 Internal Revenue Service (“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 15 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 currently available for bank loans with similar terms and average maturities, the
fair value of our consolidated long-term debt and debt maturing within one year, excluding revolving credit
agreements and commercial paper, was $4,306 million at December 31, 2016. The total book value of our
consolidated long-term debt and debt maturing within one year, net of discount and deferred financing fees and
excluding revolving credit agreements and commercial paper, was $4,112 million at December 31, 2016. 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,
2016. An increase in interest rates of 10% (from 5.0% to 5.5%, for example) at December 31, 2016 would decrease
the fair value of debt by $177 million, and a decrease in interest rates of 10% at December 31, 2016 would increase
the fair value of debt by $192 million at that date.

Revolving Credit Agreements

At December 31, 2016, we had a consolidated total of $334 million outstanding under our revolving agreements,
which are variable rate loans and fair value approximates book value. A 10% increase or decrease in borrowing
rates under the revolving credit agreements compared to the weighted average rates in effect at December 31,
2016 would increase or decrease interest expense by $1 million, respectively, for an annual period with a constant
borrowing level of $334 million.

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Commercial Paper

At December 31, 2016, ITC Holdings had $145 million of commercial paper issued and outstanding, net of
discount, under the commercial paper program. Due to the short-term nature of these financial instruments, the
carrying value approximates fair value. A 10% increase or decrease in interest rates for commercial paper would
increase or decrease interest expense by less than $1 million for an annual period with a continuous level of
commercial paper outstanding of $145 million.

Derivative Instruments and Hedging Activities

We use derivative financial instruments, including interest rate swap contracts, to manage our exposure to
fluctuations in interest rates. The use of these financial instruments mitigates exposure to these risks and the
variability of our operating results. We are not a party to leveraged derivatives and do not enter into derivative
financial instruments for trading or speculative purposes. In June 2016, we terminated $300 million of 10-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.

As of December 31, 2016, we held 10-year interest rate swap contracts with a notional amount of $100 million,
which manage interest rate risk associated with the forecasted future issuance of fixed-rate debt related to the
expected refinancing of the maturing ITC Holdings 6.05% Senior Notes, due January 31, 2018. As of December 31,
2016, ITC Holdings had $385 million outstanding under the 6.05% Senior Notes. See Note 9 to the consolidated
financial statements for further discussion on these interest rate swaps.

Credit Risk

Our credit risk is primarily with DTE Electric, Consumers Energy and IP&L, which were responsible for 20.7%,
21.7% and 25.5%, respectively, or $254 million, $267 million and $314 million, respectively, of our consolidated
billed revenues for 2016. These percentages of total billed revenues of DTE Electric, Consumers Energy and IP&L
include the collection of 2014 revenue accruals and deferrals and exclude any amounts for the 2016 revenue
accruals and deferrals that were included in our 2016 operating revenues, but will not be billed to our customers
until 2018. 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, 2016 and 2015

Consolidated Statements of Operations for the Years Ended December 31, 2016, 2015 and 2014

Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2016, 2015 and 2014
Consolidated Statements of Changes in Stockholders’ Equity for the Years Ended December 31, 2016, 2015

and 2014

Consolidated Statements of Cash Flows for the Years Ended December 31, 2016, 2015 and 2014

Notes to Consolidated Financial Statements

Schedule I — Condensed Financial Information of Registrant

Page

138

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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, 2016.

Deloitte & Touche LLP, an independent registered public accounting firm, as auditors of our consolidated financial
statements, has issued an attestation report on the effectiveness of our internal control over financial reporting as
of December 31, 2016. Deloitte & Touche LLP’s report, which expresses an unqualified opinion on the effectiveness
of our internal control over financial reporting, is included herein.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of
ITC Holdings Corp.:
Novi, Michigan

We have audited the accompanying consolidated statements of financial position of ITC Holdings Corp. and
subsidiaries (the “Company”) as of December 31, 2016 and 2015, and the related consolidated statements of
operations, comprehensive income, changes in stockholders’ equity, and cash flows for each of the three years in
the period ended December 31, 2016. Our audits also included the financial statement schedule listed in the Index
at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s
management. Our responsibility is to express an opinion on the financial statements and financial statement
schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing
the accounting principles used and significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position
of ITC Holdings Corp. and subsidiaries as of December 31, 2016 and 2015, and the results of their operations and
their cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting
principles generally accepted in the United States of America. Also, in our opinion, such financial statement
schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents
fairly, in all material respects, the information set forth therein.

As discussed in Note 3 to the financial statements, the Company has changed its method of accounting for share-
based payment accounting in 2016 due to the adoption of Accounting Standards Update 2016-09 Compensation-
Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States), the Company’s internal control over financial reporting as of December 31, 2016, based on criteria
established in the Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring
Organizations of the Treadway Commission and our report dated February 16, 2017 expressed an unqualified
opinion on the Company’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Detroit, Michigan
February 16, 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

We have audited the internal control over financial reporting of ITC Holdings Corp. and subsidiaries (the “Company”)
as of December 31, 2016, based on criteria established in the Internal Control — Integrated Framework (2013)
issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management
is responsible for maintaining effective internal control over financial reporting and for its assessment of the
effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on
Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal
control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about
whether effective internal control over financial reporting was maintained in all material respects. Our audit included
obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness
exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed
risk, and performing such other procedures as we considered necessary in the circumstances. We believe that
our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the
company’s principal executive and principal financial officers, or persons performing similar functions, and effected
by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding
the reliability of financial reporting and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company’s internal control over financial reporting includes those
policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and
fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of financial statements in accordance with generally
accepted accounting principles, and that receipts and expenditures of the company are being made only in
accordance with authorizations of management and directors of the company; and (3) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s
assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion
or improper management override of controls, material misstatements due to error or fraud may not be prevented
or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over
financial reporting to future periods are subject to the risk that the controls may become inadequate because of
changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting
as of December 31, 2016, based on the criteria established in the Internal Control — Integrated Framework (2013)
issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States), the consolidated financial statements and financial statement schedule as of and for the year ended
December 31, 2016 of the Company and our report dated February 16, 2017 expressed an unqualified opinion on
those financial statements and financial statement schedule and included an explanatory paragraph regarding the
Company's adoption of Accounting Standards Update 2016-09 Compensation-Stock Compensation (Topic 718):
Improvements to Employee Share-Based Payment Accounting.

/s/ DELOITTE & TOUCHE LLP

Detroit, Michigan
February 16, 2017

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ITC HOLDINGS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

(In millions, except share data)

Current assets

Cash and cash equivalents

Accounts receivable

Inventory

Regulatory assets

Income tax receivable

Prepaid and other current assets

Total current assets

ASSETS

December 31,

2016

2015

108

233

104

—

169

Property, plant and equipment (net of accumulated depreciation and amortization of $1,575 and

$1,488, respectively)

6,698

6,110

Other assets

Goodwill

Intangible assets (net of accumulated amortization of $32 and $28, respectively)

Regulatory assets

Deferred financing fees (net of accumulated amortization of $2 and $1, respectively)

Other

Total other assets

TOTAL ASSETS

Current liabilities

Accounts payable

Accrued compensation

Accrued interest

Accrued taxes

Regulatory liabilities

LIABILITIES AND STOCKHOLDERS’ EQUITY

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 15)

STOCKHOLDERS’ EQUITY

Common stock, without par value, 235,000,000 shares authorized as of December 31, 2016, and
224,203,112 and 152,699,077 shares issued and outstanding at December 31, 2016 and 2015,
respectively

Retained earnings

Accumulated other comprehensive income

Total stockholders’ equity

950

247

1,292

8,223

950

233

1,276

7,555

100

124

129

235

633

964

249

395

719

735

255

4,355

4,034

892

1,007

1,901

829

876

1,709

7,555

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY

8,223

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
Loss on extinguishment of debt
Other income
Other expense

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

Year Ended December 31,
2015

2014

2016

1,125 $

1,045 $

1,023

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 $

112
115
128
76
(1)
430
593

187
(21)
29
(1)
5
199
394
150
244

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

2016

Year Ended December 31,
2015

2014

246 $

242 $

244

(2)

(1)

(2)
244 $

(1)
241 $

(2)

(2)
242

See notes to consolidated financial statements.

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ITC HOLDINGS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN
STOCKHOLDERS’ EQUITY

Accumulated
Other
Comprehensive

Total
Stockholders’

Retained

Common Stock

Earnings

Income (Loss)

Equity

1,014

(In millions)
BALANCE, DECEMBER 31, 2013
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, 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 13)

Settlement of share-based awards associated with the Merger

(Note 13)

Contribution from ITC Investment Holdings Inc. for the settlement of

shared-based awards associated with the Merger (Note 13)

Tax benefit for excess tax deductions of share-based compensation

(Note 3)

Other comprehensive loss, net of tax (Note 13)
Other

BALANCE, DECEMBER 31, 2016

593

244

—

(96)

—

—
741

242

—

(108)
—

—

1
876

246

—
(90)
(33)
—

—

(1)

—

—
—
1,007

—
(134)

—

2
924

—

(137)

—

1
829

—

(9)
—

—

(137)

137

—

—
2
892

—

(2)
—

—

(1)
—

—

(2)
—

1,614

244
(134)

(96)

(2)
2

1,670

242

(137)

(108)
11

(1)
2

1,709

246

(9)
(90)
(33)
11

(138)

137

(2)
2

1,901

See notes to consolidated financial statements.

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ITC HOLDINGS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES

Net income

Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation and amortization expense

Recognition, refund and collection of revenue accruals and deferrals — including accrued interest

Deferred income tax expense

Allowance for equity funds used during construction

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

Loss on extinguishment of debt

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
Tax benefit on the excess tax deduction of share-based compensation
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 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

Tax benefit on the excess tax deduction of share-based compensation
Advance for forward contract of accelerated share repurchase program
Return of unused advance for forward contract of accelerated share repurchase program

Other

Net cash provided by financing activities

NET 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,
2015

2014

2016

246

242

244

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)

145
(54)
77
(28)
—

—

(1)
—
—
2
(7)
—
15
(12)
9
120
26
556

(701)
17
(16)
(700)

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

—

12
—
—

(4)
130
(14)
28

128

(4)

90
(21)
—

(12)
—
—
6
(19)
1
20
(8)
(5)
48
(13)
502

(753)
20
(2)
(735)

799
1,660
110
—
(299)
(1,618)
(189)
21
(96)
—
6
(29)
(134)

—

8
(20)
20
(12)
227

(6)

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1. GENERAL

ITC HOLDINGS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ITC Holdings Corp. (“ITC Holdings,” and together with its subsidiaries, “we,” “our” or “us”) and its subsidiaries
are engaged in the transmission of electricity in the United States. Through our operating subsidiaries,
ITCTransmission, METC, ITC Midwest, ITC Great Plains and ITC Interconnection (together, our “Regulated
Operating Subsidiaries”), we operate high-voltage systems in Michigan 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 operate, maintain and invest in transmission infrastructure
in order to enhance system integrity and reliability, reduce transmission constraints and allow new generating
resources to interconnect to our transmission systems. We also are pursuing transmission development projects
not within our existing systems, which are intended to improve overall grid reliability, lower electricity congestion
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.
The Midcontinent Independent System Operator, Inc. (“MISO”) bills and collects revenues from ITCTransmission,
METC and ITC Midwest (“MISO Regulated Operating Subsidiaries”) customers. The Southwest Power Pool, Inc.
(“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 Inc. (“Fortis”), FortisUS Inc. (“FortisUS”), Element Acquisition Sub Inc. (“Merger
Sub”) and ITC Holdings entered into an agreement and plan of merger (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 (the “Merger”). On April 20, 2016, FortisUS assigned
its rights, interest, duties and obligations under the Merger Agreement to ITC Investment Holdings Inc. (“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 Private Limited (“GIC”) for GIC 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 New York Stock Exchange (“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. Under the Merger Agreement, outstanding
share-based awards vested as described in Note 13. The per share amount of 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.

For the year ended December 31, 2016, we expensed external legal, advisory and financial services fees related
to the Merger of $55 million and certain internal labor and associated costs related to the Merger of approximately
$58 million, including approximately $41 million of expense recognized due to the accelerated vesting of the share-
based awards described in Note 13. 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.

See Note 15 for legal matters associated with the Merger with Fortis.

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3. RECENT ACCOUNTING PRONOUNCEMENTS

Recently Adopted Pronouncements

Amendment to the Balance Sheet Presentation of Debt Issuance Costs

In April 2015, the Financial Accounting Standards Board (“FASB”) issued authoritative guidance that amends
the balance sheet presentation of debt issuance costs. This new standard requires debt issuance costs to be
shown as a direct deduction from the carrying amount of the related debt, consistent with debt discounts. The
guidance is effective for annual periods, and interim periods within those annual periods, beginning after December
15, 2015. On January 1, 2016, we adopted this guidance retrospectively and have applied this change to all
amounts presented in our consolidated statements of financial position. The following shows the impact of this
adoption on our previously reported consolidated statement of financial position as of December 31, 2015:

(in millions)

Reported

Adjustment

Adjusted

Deferred financing fees (net of accumulated amortization)
Debt maturing within one year
Long-term debt

29 $

395
4,061

(27) $
—
(27)

2
395
4,034

We have accounted for this adoption as a change in accounting principle that is required due to a change in
the authoritative accounting guidance. In connection with implementing this guidance, we adopted an accounting
policy to present unamortized debt issuance costs associated with revolving credit agreements, commercial paper
and other similar arrangements as an asset that is amortized over the life of the particular arrangement. In addition,
we present debt issuance costs incurred prior to the associated debt funding as an asset for all other debt
arrangements. This standard did not impact our consolidated statements of operations or cash flows.

Simplification of Employee Share-Based Payment Accounting

In March 2016, the FASB issued authoritative guidance that simplifies several aspects of the accounting for
employee share-based payment transactions. The new guidance (1) requires that an entity recognize all excess
tax benefits and tax deficiencies as income tax benefit or expense in the income statement, (2) allows an entity to
elect as an accounting policy to either estimate forfeitures or account for forfeitures when they occur, (3) modifies
the current exception to liability classification of an award when an employer uses a net-settlement feature to
withhold shares to meet the employer’s minimum statutory tax withholding requirement to apply if the withholding
amount does not exceed the maximum statutory tax rate and (4) specifies the statement of cash flow presentation
for excess tax benefits and cash payments to taxing authorities when shares are withheld to meet tax withholding
requirements.

We elected to early adopt the guidance during the fourth quarter of 2016. Upon adoption, we elected an
accounting policy of recognizing forfeitures as they occur. The impact of this change was not material. In addition,
we recorded a deferred tax asset through an adjustment to retained earnings 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. These aspects were adopted on a modified
retrospective basis as of January 1, 2016. We also recorded an increase in deferred tax assets and a credit to
income tax expense in 2016 for a total of $27 million for excess tax benefits generated during the year ended
December 31, 2016; this change was adopted on a prospective basis as of January 1, 2016.

As a result of adoption, we began presenting excess tax benefits and deficiencies within operating activities on
the statement of cash flows and adopted this change prospectively as of January 1, 2016; previously, such amounts
were presented within financing activities. Therefore, the statements of cash flows for prior periods have not been
adjusted. There were no other material impacts to our consolidated financial statements as a result of the other
aspects of the guidance.

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.

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Revenue Recognition

In May 2014, the FASB issued authoritative guidance requiring entities to apply a new model for recognizing
revenue from contracts with customers. The guidance will supersede 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. The majority of our revenue is generated from
sales based on tariff rates, as approved by FERC, and is considered to be in the scope of the new guidance.
However, we do not expect that the adoption of this guidance will have a material impact on our consolidated
results of operations, cash flows or financial position. We continue to closely monitor outstanding industry specific
interpretative issues, including contributions in aid of construction.

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 effective 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 effective of applying the standard would be recognized at the date of initial adoption, January 1,
2018. While we expect to use the modified retrospective approach, we continue to monitor industry developments
and the outcome of those matters may impact our ultimate decision regarding transition method.

Classification 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. We are currently assessing the impacts 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
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. We are currently
assessing the impacts this guidance will have on our consolidated financial statements, including our disclosures.

4. SIGNIFICANT ACCOUNTING POLICIES

A summary of the major accounting policies followed in the preparation of the accompanying consolidated
financial statements, which conform to accounting principles generally accepted in the United States of America
(“GAAP”), is presented below:

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

all intercompany balances and transactions.

Use of Estimates — The preparation of the consolidated financial statements in accordance with GAAP
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

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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, 2016, 2015 and 2014:

(In millions)
Supplementary cash flows information:

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

Supplementary non-cash investing and financing activities:

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

assets (b)

Allowance for equity funds used during construction

____________________________

Year Ended December 31,
2015

2016

2014

190 $

191 $

185
45

93 $
35

110 $

91
21

(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 (“IRS”) in August 2016, which resulted from the election of
bonus depreciation as described in Note 5.

(b) Amounts consist of current liabilities for construction labor and materials that have not been included in
investing activities. These amounts have not been paid for as of December 31, 2016, 2015 or 2014,
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, 2016 and 2015, 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 $149 million, $136 million and $119 million for 2016, 2015 and 2014, respectively.

Property, plant and equipment in service at our Regulated Operating Subsidiaries is stated at its original
cost when first devoted to utility service. The gross book value of assets retired less salvage proceeds is
charged to accumulated depreciation. The provision for depreciation of transmission assets is a significant
component of our Regulated Operating Subsidiaries’ cost of service under FERC-approved rates.
Depreciation is computed over the estimated useful lives of the assets using the straight-line method for
financial reporting purposes and accelerated methods for income tax reporting purposes. The composite
depreciation rate for our Regulated Operating Subsidiaries included in our consolidated statements of
operations was 2.0%, 2.1% and 2.1% for 2016, 2015 and 2014, 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 48 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 an allowance for the cost of equity and

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borrowings used during construction (“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,
$7 million and $5 million was a reduction to interest expense for 2016, 2015 and 2014, respectively. Certain
projects at ITC Great Plains have been granted an incentive to include construction work in progress balances
in rate base and we do not record AFUDC on those projects.

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.

Our investments in transmission facilities are recorded to property, plant and equipment, and are recorded
net of any contribution in aid of construction. Contributions in aid of construction of $11 million, $17 million
and $20 million were recorded as reductions to property, plant and equipment during the years ended
December 31, 2016, 2015 or 2014, respectively, and are included as cash inflows provided by investing
activities in our consolidated statements of cash flows when received. 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 recognized, net of tax, in the accumulated
other comprehensive income component of equity. Any unrealized losses (where cost exceeds fair market
value) on the investments will also be recorded in the accumulated other comprehensive income component
of equity, 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.

Goodwill — Goodwill is not subject to amortization; however, goodwill is required to be assessed for
impairment, and a resulting write-down, if any, is to be reflected in operating expense. We have goodwill
recorded relating to our acquisitions of ITCTransmission and METC and ITC Midwest’s acquisition of the
Interstate Power and Light Company (“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 it is more likely

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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 two-step, 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, 2016 and
determined that no impairment exists. There were no events subsequent to October 1, 2016, including the
Merger consummated on October 14, 2016, 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, 2016, 2015 and
2014.

Asset Retirement Obligations — A conditional asset retirement obligation is a legal obligation to perform
an asset retirement activity in which the timing and/or method of settlement are conditional on a future event
that may or may not be within our control. We have identified conditional asset retirement obligations primarily
associated with the removal of equipment containing polychlorinated biphenyls (“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. The standards for asset retirement obligations applied to our Regulated
Operating Subsidiaries require us to recognize regulatory assets for the timing differences between the
incurred costs to settle our legal asset retirement obligations and the recognition of such obligations under
the standards set forth by the FASB. There were no significant changes to our asset retirement obligations
in 2016. Our asset retirement obligations as of December 31, 2016 and 2015 of $5 million 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 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.

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 in accordance with GAAP. 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

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refund is probable and can be reasonably estimated. This reserve is recorded as a reduction to operating
revenues.

The cost-based formula rates at our Regulated Operating Subsidiaries include a true-up mechanism,
whereby they compare their actual revenue requirements to their billed revenues for each year to determine
any over- or under-collection of revenue requirements and record a revenue accrual or deferral for the
difference. Refer to Note 5 under “Cost-Based Formula Rates with True-Up Mechanism” for a discussion of
our revenue accounting under our cost-based formula rates.

Comprehensive Income (Loss) — Comprehensive income (loss) is the change in common stockholders’
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 financial statements or tax returns. Deferred 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 statement 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, 2016, we have not recognized any uncertain income tax positions.

We file income tax returns with the Internal Revenue Service 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 2012 to 2015. 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.

5. REGULATORY MATTERS

Rate of Return on Equity Complaints

See “Rate of Return on Equity Complaints” in Note 15 for a discussion of the complaints.

Cost-Based Formula Rates with True-Up Mechanism

The transmission revenue requirements at our Regulated Operating Subsidiaries are set annually, using FERC-
approved formula rates (“formula rates”), and remain in effect for a one-year period. By updating their formula 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 rates do not require further action or FERC filings each year, although the template
inputs remain subject to legal challenge at the FERC. Our Regulated Operating Subsidiaries will continue to use
formula rates to calculate their respective annual revenue requirements unless the FERC determines the rates to
be unjust and unreasonable or another mechanism is determined by the FERC to be just and reasonable. See
“Rate of Return on Equity Complaints” in Note 15 for detail on return on equity (“ROE”) matters.

Our formula rates include a true-up mechanism, whereby our Regulated Operating Subsidiaries compare their
actual revenue requirements to their billed revenues for each year to determine any over- or under-collection of
revenue requirements. Revenue is recognized for services provided during each reporting period based on actual
revenue requirements calculated using the formula rates. 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
the formula rates.

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The net changes in regulatory assets and liabilities associated with our Regulated Operating Subsidiaries’
formula rate revenue accruals and deferrals, including accrued interest, were as follows during the year ended
December 31, 2016:

(In millions)

Net regulatory liability as of December 31, 2015

Net refund of 2014 revenue deferrals and accruals, including accrued interest

Net revenue deferral for the year ended December 31, 2016

Net accrued interest payable for the year ended December 31, 2016

Net regulatory liability as of December 31, 2016

Total

(3)

(20)

(1)

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, 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, 2016

ITCTransmission Regional Cost Allocation Refund

Total

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 Phase Angle
Regulating Transformers (“PARs”) among MISO and other FERC-approved Regional Transmission Organizations
(“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 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. As a result of the
FERC order, ITCTransmission will collect the amounts refunded, plus interest, from network customers. 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 has 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.

ITC Interconnection

ITC Interconnection was formed in 2014 by ITC Holdings to pursue transmission investment opportunities. On
June 1, 2016, ITC Interconnection acquired certain transmission assets from a merchant generating company and
placed a newly constructed 345 kV transmission line in service. As a result, ITC Interconnection became a
transmission owner in PJM Interconnection, 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.
The financial results of ITC Interconnection are currently not material to our consolidated financial statements.

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 allows a transmission owner to unilaterally
elect to fund network upgrades and recover such costs from the interconnection customer. In this order, the FERC

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suggested the MISO funding policy be revised to require mutual agreement between the interconnection customer
and transmission owner to utilize the election to fund network upgrades. 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. ITCTransmission, METC and ITC Midwest, along
with another MISO TO, are currently appealing the FERC’s orders on this issue. 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 and 2015, our MISO Regulated Operating Subsidiaries had recorded an aggregate
refund liability of $2 million and $10 million, respectively.

Challenges 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. The FERC denied IP&L’s request
that ITC Midwest be required to elect bonus depreciation in any past or future years; however, stakeholders will
be able to challenge any decision by ITC Midwest not to take bonus depreciation in future years. 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 resolution of a private letter ruling matter from the IRS. In a separate but related matter, on April 15,
2016, Consumers Energy filed a formal challenge, or in the alternative, a complaint under Section 206 of the FPA,
with the FERC against METC relating to METC’s historical practice of opting out of using bonus depreciation. On
July 8, 2016, the FERC denied Consumers Energy’s formal challenge and dismissed the complaint without
prejudice.

These consolidated financial statements reflect the election of bonus depreciation for tax years 2015 and 2016
and the corresponding effects on 2016 revenue requirements for our Regulated Operating Subsidiaries.
Additionally, as required by the March 11, 2016 FERC order, we have simulated the election of bonus depreciation
for ITC Midwest’s 2015 revenue requirement and included the impact of the corresponding refund obligation in
these consolidated financial statements. The total impact from reflecting the election of bonus depreciation as
described above was lower revenues of $20 million and lower net income of approximately $12 million for the
year ended December 31, 2016 as compared to the same period if bonus depreciation was not reflected. These
matters also resulted in additional net deferred income tax liabilities of approximately $109 million and a
corresponding income tax receivable of $12 million as of December 31, 2016, and income tax refunds of $128
million, which were received from the IRS in August 2016. We are unable to predict the final outcome of this matter;
however, the election of bonus depreciation will result in higher cash flows in the year of the election and reduce
our rate base and therefore decrease our revenues and net income over the tax lives of the eligible assets.

ITC Midwest’s Rate Discount

As part of the orders by the Iowa Utility Board and the Minnesota Public Utilities Commission approving ITC
Midwest’s acquisition of the IP&L transmission assets, ITC Midwest agreed to provide a rate discount of $4 million
per year to its customers for eight years, beginning in the first year customers experience an increase in transmission

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charges following the consummation of the ITC Midwest asset acquisition. From 2009 through 2016, ITC Midwest’s
net revenue requirement was reduced by $4 million for each year. The rate discount is recognized in revenues
when we provide the service and charge the reduced rate that includes the rate discount.

6. REGULATORY ASSETS AND LIABILITIES

Regulatory Assets

The following table summarizes the regulatory asset balances at December 31, 2016 and 2015:

(In millions)
Regulatory Assets:

Current:

2016

2015

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

2016 and 2015) (a)

24 $

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,

2016 and 2015) (a)

ITCTransmission ADIT Deferral (net of accumulated amortization of $42 and $39

as of December 31, 2016 and 2015, respectively)

METC ADIT Deferral (net of accumulated amortization of $24 and $22 as of

December 31, 2016 and 2015, respectively)

METC Regulatory Deferrals (net of accumulated amortization of $7 as of

December 31, 2016 and 2015)

Income taxes recoverable related to AFUDC equity
ITC Great Plains start-up, development and pre-construction
Pensions and postretirement
Income taxes recoverable related to implementation of the Michigan Corporate

Income Tax

Accrued asset removal costs

Total non-current

Total

____________________________

124
11
25
9

16
247

300 $

—

103
13
19
9

12
233

248

(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.”

ITCTransmission ADIT Deferral

The carrying amount of the ITCTransmission Accumulated Deferred Income Tax (“ADIT”) Deferral is the
remaining unamortized balance of the portion of ITCTransmission’s purchase price in excess of the fair value of
net assets acquired approved for inclusion in future rates by the FERC. ITCTransmission earns a return on the
remaining unamortized balance of this regulatory asset that is included in rate base. 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.
ITCTransmission recorded amortization expense of $3 million annually during 2016, 2015 and 2014, which is
included in depreciation and amortization and recovered through ITCTransmission’s cost-based formula rate
template.

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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 from Consumers Energy approved for inclusion
in future rates by the FERC. The original amount 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 earns a return on
the remaining unamortized balance of this regulatory asset that is included in rate base. METC recorded
amortization expense of $2 million annually during 2016, 2015 and 2014, which is included in depreciation and
amortization and recovered through METC’s cost-based formula rate template.

METC Regulatory Deferrals

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 Michigan Transco Holdings, LLC (“MTH”) acquired METC from Consumers
Energy (the “METC Regulatory Deferrals”). The original amount recorded for this regulatory asset of $15 million
is recognized in rates and amortized over 20 years beginning January 1, 2007. METC earns a return on the
remaining unamortized balance of this regulatory asset that is included in rate base. METC recorded amortization
expense of $1 million annually during 2016, 2015 and 2014, 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. We do not earn a
return on this regulatory asset and the related deferred tax liabilities do not reduce 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. The unamortized balance of these regulatory assets is included in
rate base and amortized 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 accumulated other comprehensive income
(“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. Our Regulated Operating Subsidiaries do not earn a return on the balance of this regulatory asset.

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

In May 2011, the Michigan Business Tax (“MBT”) was repealed and replaced with the Michigan Corporate
Income Tax (“CIT”), effective January 1, 2012. Under the CIT, 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 MBT had also included a modified gross receipts tax that allowed for deductions and
credits for certain activities, none of which are part of the CIT. The change in Michigan tax law required us in 2011
to remove deferred income tax balances recognized under the MBT and establish new deferred income tax balances
under the CIT, and the net result was incremental deferred state income tax liabilities at both ITCTransmission and
METC. Under our cost-based formula rate, the future taxes receivable as a result of the tax law change has resulted

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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 do not
earn a return on the balance of this regulatory asset and the related net deferred tax liabilities do not reduce 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 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, which is an increase to rate
base.

Regulatory Liabilities

The following table summarizes the regulatory liability balances at December 31, 2016 and 2015:

(In millions)
Regulatory Liabilities:

Current:

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

December 31, 2016 and 2015, respectively) (a)

Refund related to the formula rate template modifications (including accrued

interest of $1 and less than $1 as of December 31, 2016 and 2015,
respectively) (b)

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

of $9 as of December 31, 2016) (c)

Total current

Non-current:

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

December 31, 2016 and 2015, respectively) (a)

Accrued asset removal costs
Refund related to the formula rate template modifications (including accrued

interest of less than $1 as of December 31, 2015) (b)

Estimated potential refund related to return on equity complaints (including

accrued interest of $6 as of December 31, 2016 and 2015) (c)

Excess state income tax deductions

Total non-current

Total

____________________________

2016

2015

9 $

118

129

68
—

140

9
249

378 $

—

70
2

168

9
255

300

(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.”

Complaints.”

Accrued Asset Removal Costs

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removal expenditures incurred are charged to this regulatory liability. Our Regulated Operating Subsidiaries include
this item within accumulated depreciation for rate-making purposes, which is a reduction to rate base.

Excess State Income Tax Deductions

We have taken 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 and the related deferred
tax assets do not affect rate base.

7. GOODWILL AND INTANGIBLE ASSETS

Goodwill

At December 31, 2016 and 2015, 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. The carrying amounts of the intangible asset for the METC Regulatory Deferrals and the
METC ADIT Deferral were $20 million and $8 million, respectively, as of December 31, 2016, and $22 million and
$9 million, respectively, as of December 31, 2015. 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 two regional cost sharing projects in Kansas. The carrying
amount of these intangible assets was $14.7 million and $14.4 million (net of accumulated amortization of $1 million
and $1 million, respectively) as of December 31, 2016 and 2015, respectively. The amortization period for these
intangible assets is 50 years.

During each of the years ended December 31, 2016, 2015 and 2014, 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, 2016 to be as follows:

(In millions)
2017
2018
2019
2020
2021
2022 and thereafter

Total

3
3
3
3
3
28
43

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8. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment — net consisted of the following at December 31, 2016 and 2015:

(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

2016

2015

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

7,086
426
55
13
18
7,598
(1,488)
6,110

Additions to property, plant and equipment in service and construction work in progress during 2016 and 2015
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, 2016 and 2015:

(Amounts in millions)

2016

2015

ITC Holdings 5.875% Senior Notes, due September 30, 2016 (a)

— $

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

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 Term Loan Credit Agreement, due September 30, 2016 (a)

ITC Holdings Revolving Credit Agreement, due March 28, 2019

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

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 Revolving Credit Agreement, due March 28, 2019

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 Term Loan Credit Agreement, due December 7, 2018

METC Revolving Credit Agreement, due March 28, 2019

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 Revolving Credit Agreement, due March 28, 2019

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

ITC Great Plains Revolving Credit Agreement, due March 28, 2019

Total principal

Unamortized deferred financing fees and discount

Total debt

____________________________

200

385

200

250

400

300

400

—

145

100

285

100

150

200

—

175

100

225

127

150

139

200

385

200

250

400

300

—

161

138

100

285

100

150

—

200

175

100

225

150

4,624

(34)

4,460

(31)

4,590

4,429

(a) As of December 31, 2016 and 2015, there was $235 million and $395 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.

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The annual maturities of debt as of December 31, 2016 are as follows:

(In millions)
2017
2018
2019
2020
2021
2022 and thereafter

Total

ITC Holdings

Commercial Paper Program

235
485
334
235
—
3,335
4,624

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, 2016,
ITC Holdings had approximately $145 million of commercial paper issued and outstanding under the program,
with a weighted-average interest rate of 1.0% and weighted average remaining days to maturity of 7 days. The
proceeds from issuances under the program during the year ended December 31, 2016 were used to repay and
retire the $139 million of ITC Holdings’ 5.875% Senior Notes, due September 30, 2016, and for general corporate
purposes, including the repayment of borrowings under ITC Holdings’ revolving credit agreement. The amount
outstanding as of December 31, 2016 was classified as debt maturing within one year in the consolidated statements
of financial position.

Unsecured Notes

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 discussed above. These Notes were issued under
ITC Holdings’ indenture, dated April 18, 2013.

METC

Senior Secured Notes

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.

Term Loan Credit Agreement

On December 8, 2015, METC entered into an unsecured, unguaranteed term loan credit agreement due
December 7, 2018, under which METC borrowed $200 million. The proceeds were used to repay the $175 million
of 5.75% Senior Secured Notes, due December 10, 2015, and for general corporate purposes. This borrowing
was repaid in full as of December 31, 2016. The weighted-average interest rate throughout the life of the loan was
1.4%.

ITC Midwest

On April 7, 2015, ITC Midwest issued $225 million aggregate principal amount of 3.83% First Mortgage Bonds,
Series G, due April 7, 2055. The proceeds from the issuance were used for general corporate purposes, including
the repayment of borrowings under ITC Midwest’s revolving credit agreement. ITC Midwest’s First Mortgage Bonds
are issued under its first mortgage and deed of trust and secured by a first mortgage lien on substantially all of its
property.

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

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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. The interest rate swaps listed below manage interest
rate risk associated with the forecasted future issuance of fixed-rate debt related to the expected refinancing of
the maturing ITC Holdings 6.05% Senior Notes, due January 31, 2018. As of December 31, 2016, ITC Holdings
had $385 million outstanding under the 6.05% Senior Notes.

Interest Rate Swaps
(In millions, except percentages)
July 2016 swaps
August 2016 swap

Total

Notional Amount
75
$
25
100

Weighted Average
Fixed Rate
1.616%
1.599%

Original Term
10 years
10 years

Effective Date
January 2018
January 2018

The 10-year term interest rate swaps call for ITC Holdings to receive interest quarterly at a variable rate equal
to LIBOR and pay interest semi-annually at various fixed rates effective for the 10-year period beginning January
31, 2018, after the agreements have been terminated. The agreements include a mandatory early termination
provision and will be terminated no later than the effective date of the interest rate swaps of January 31, 2018.
The interest rate swaps have been determined to be highly effective at offsetting changes in the fair value of the
forecasted interest cash flows associated with the expected debt issuance, resulting from changes in benchmark
interest rates from the trade date of the interest rate swaps to the issuance date of the debt obligation.

The interest rate swaps qualify for cash flow hedge accounting treatment, whereby any gain or loss recognized
from the trade date to the effective date for the effective portion of the hedge is recorded net of tax in AOCI. This
amount will be accumulated and amortized as a component of interest expense over the life of the forecasted debt.
As of December 31, 2016, the fair value of the derivative instruments was an asset of $8 million. None of the
interest rate swaps contain credit-risk-related contingent features. Refer to Note 12 for additional fair value
information.

In June 2016, we terminated $300 million of 10-year interest rate swap contracts that managed the interest rate
risk associated with the unsecured Notes issued by ITC Holdings described below. A summary of the terminated
interest rate swaps is provided below:

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

Amount

300

Weighted Average
Fixed Rate of
Interest Rate Swaps
1.99%

Comparable
Reference Rate
of Notes
1.37%

Loss on
Derivatives
17
$

Settlement
Date
June 2016

The interest rate swaps qualified for cash flow hedge accounting treatment and the loss of $17 million was
recognized in June 2016 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. The ineffective portion of the
hedges was recognized in the consolidated statement of operations for the year ended December 31, 2016 and
was not material.

Revolving Credit Agreements

At December 31, 2016, ITC Holdings and certain of its Regulated Operating Subsidiaries had the following

unsecured revolving credit facilities available:

(Amounts 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
250
150
1,000 $

327 (c)

56
69
123
91
666

73 $
44
31
127
59

334 $

Weighted Average
Interest Rate on
Outstanding
Balance

2.0%
1.7%
1.7%
1.7%
1.7%

(d)

(e)

(e)
(e)

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

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____________________________

(a) Included within long-term debt.

(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. While
outstanding commercial paper does not reduce available capacity under ITC Holdings’ revolving credit
agreement, the unused capacity under this agreement adjusted for the commercial paper outstanding was
$182 million as of December 31, 2016.

(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.

On April 7, 2016, each of the unsecured revolving credit agreements described above was amended to allow

for the consummation of the Merger.

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 debt to capitalization
ratios and maintaining certain interest coverage ratios. As of December 31, 2016, we were not in violation of any
debt covenant.

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)
AFUDC equity
Excess tax deductions for share-based compensation (a)
Other — net

Total income tax provision

____________________________

2016

2015

2014

120 $
3
(11)
(23)
8

97 $

134 $

14
(8)
—
2
142 $

138
16
(6)
—
2
150

(a) Amount relates to a federal income tax benefit for excess tax deductions generated in 2016 as a result of

adopting the new accounting guidance associated with share-based payments as described in Note 3.

Components of the income tax provision were as follows:

(In millions)
Current income tax (benefit) expense (a)
Deferred income tax expense (b)(c)

Total income tax provision

2016

2015

2014

(122) $
219

97 $

65 $
77

142 $

60
90
150

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____________________________

(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) 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 as described in Note 3.

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 financial statements.

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 (a)
Refund liabilities (a)
Pension and postretirement liabilities
State income tax NOLs (net of federal benefit) (b)
Share-based compensation
Other — net (c)

Net deferred tax liabilities

Gross deferred income tax liabilities
Gross deferred income tax assets

Net deferred tax liabilities

____________________________

(a) Described in Note 6.

2016

2015

$
$

(1,026) $
140
(11)
(15)
(163)
(11)
56
23
47
—
(4)
(964) $
(1,252) $
288
(964) $

(679)
1
(12)
(15)
(148)
—
70
19
20
14
(5)
(735)
(888)
153
(735)

(b) 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 as described in Note 3.

and 2015.

We have federal income tax net operating losses (“NOLs”) and capital losses as of December 31, 2016, both
of which we expect to use prior to their expirations starting in 2036 and 2018, respectively. We also have state
income tax NOLs as of December 31, 2016, 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

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Retirement Income Security Act of 1974, plus additional amounts as we determine appropriate. We made contributions
of $3 million, $4 million and $4 million to the retirement plan in 2016, 2015 and 2014, respectively. We expect to
contribute $3 million to the retirement plan in 2017.

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 $42 million and $36 million at December 31,
2016 and 2015, respectively, are not included in the plan asset amounts presented below, but are included in other
assets on our consolidated statement of financial position. For the years ended December 31, 2016, 2015 and 2014,
we contributed $5 million, $9 million and $5 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, 2016 and December 31, 2015 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

2016

50.3%
49.7%
100.0%

2015

50.4%
49.6%
100.0%

Net periodic benefit cost for the pension plans during 2016, 2015 and 2014 was as follows by component:

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

Net pension cost

2016

2015

2014

6 $
4
(4)
4

10 $

6 $
4
(3)
4

11 $

5
4
(4)
2
7

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, 2016 and 2015:

(In millions)
Change in Benefit Obligation:

Beginning projected benefit obligation
Service cost
Interest cost
Actuarial net (loss) gain
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

2016

2015

$
$

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

58
5
3
(2)
64
(52)

(56)
(55)
(111)

(52)
4
(4)
(52)

25
25

$
$

(96)
(6)
(4)
6
3
(97)

56
—
4
(2)
58
(39)

(49)
(41)
(90)

(45)
6
—
(39)

19
19

Actuarial assumptions used to determine the benefit obligation for the pension plans at December 31, 2016, 2015

and 2014 are as follows:

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

____________________________

2016
4.00%

4.00%

2015
4.26%

4.00%

2014
3.95%

4.00%

(a) The prior year discount rate assumptions have been presented to conform to current year 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,

2016, 2015 and 2014 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

____________________________

2016
4.46%

3.62%

4.00%

6.40%

2015
3.95%

3.95%

4.00%

6.70%

2014
4.80%

4.80%

4.00 - 6.00%

6.75%

(a) The prior year discount rate assumptions have been presented to conform to current year weighted average

presentation.

At December 31, 2016, 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
2017
2018
2019
2020
2021
2022 through 2026

6
6
6
7
7
45

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, 2016 and 2015, there were no transfers between levels.

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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 fair value measurement of the retirement plan assets as of December 31, 2015, 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)

24 $

5
29
58 $

— $
—
—
— $

—
—
—
—

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

30% Weight /
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);
and

ITC Midwest - at least 63% of
caused, unplanned, sustained
outages, 34.5 kV and above,
that impact end-use customers
are restored at point of
interconnection within 90
minutes).

Each target worth 5%.

Target is reflective of goal to
complete the normal
maintenance schedule of high
priority maintenance activities.
Complete high priority 2016
Field O&M Initiatives for:

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

Each subsidiary target worth
5%.

Target continues to tie to
external guidance on the current
year capital project plan.

The maximum payout
represents the midpoint of our
2016 capital investment
guidance range, with a threshold
level also established.

Total Bonus (as a percent of target bonus level)

____________________________

Potential
Payout

2016 Results
20% ITCTransmis
sion - 11

Actual
Payout

20%

METC - 15

ITC Midwest
- 59/ 41

ITC Midwest
- 65.6%

15% All high
priority
initiatives
completed

15%

15 - 25% Midpoint of

25%

guidance
achieved

60%

200%

60%

180%

(1) Net Income was risk-adjusted. Targets were adjusted for any potential impacts associated with changes to
the MISO ROE refund estimate (and associated interest expense) assumed in the budget, amounts
recognized for actual or probable rate refunds (including interest expense) as a result of Section 205 or 206

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proceedings at FERC (including the retroactive and prospective effects of any items requiring refunds when
not included in establishing the targets), the impact associated with asset impairments and gain/losses
associated with debt extinguishment. The targets also assumed that bonus depreciation was not used by
the Company. Because the Company was required to elect bonus depreciation, actual amounts were adjusted
to eliminate the effect of bonus depreciation for all relevant periods for purposes of measuring achievement
of the goal.

(2) Total Shareholder Return was compared to the Dow Jones Utility Average Index companies. Total
Shareholder Return must be positive for the year and must exceed the 50th percentile of the Dow Jones
Utility Average Companies before there would be any payout for meeting this goal, as illustrated below:

Total Shareholder Return relative to each of the Dow Jones Utility
Average Companies

Payout % of Salary

1st to 50th percentile

51st to 60th percentile

61st to 70th percentile

71st to 80th percentile

81st to 90th percentile

91st to 100th percentile

—%

20%

40%

60%

80%

100%

We computed Total Shareholder Return as follows:

A: Calculated the average of the closing prices from October 5, 2015 to December 31, 2015
B: Calculated the average of the closing prices from July 15, 2016 to October 12, 2016
C: Calculated total dividend paid per share in 2016
Total Return to Shareholders: (B — A + C)/A

Bonuses were based on 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
2016 were as follows:

NEO

Linda H. Blair
Gretchen Holloway
Jon E. Jipping
Daniel J. Oginsky
Christine Mason Soneral
Joseph L. Welch
Rejji P. Hayes

% of Base Salary
100%
40%
100%
100%
100%
125%
100%

Ms. Blair’s total target cash compensation, in her new role as President and CEO, is near the utility industry
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. Ms. Holloway’s target bonus level reflects her target incentive for her role as Vice President,
Finance and Treasurer.

Upon closing of the Merger and in accordance with the Merger Agreement, a prorated portion of the annual
bonus through the closing of the Merger was paid out at 200% of the target bonus levels to our NEOs except for Ms.
Mason Soneral and Mr. Hayes, who each reached an agreement with the Company for part of their 2016 annual
bonus to be paid in the ordinary course in accordance with their respective employment agreement and the Company’s
past practices based on actual 2016 performance. The prorated portion of the annual bonus for the period after the
Merger through the end of the year and the portion of Ms. Mason Soneral’s bonus agreed to be paid after year end
were paid out based on actual performance as set forth in the tables above. Mr. Welch’s annual corporate performance
bonus and an additional cash bonus of $250,000 that he was awarded in May 2016 were paid in full in connection

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with his retirement from the Company and the October 2016 letter agreement amending his employment agreement.
Mr. Hayes did not receive any further bonus after year end due to his prior resignation.

The methodology for calculating the amounts to be paid to NEOs and other employees in connection with
the annual corporate performance bonus were jointly determined by Fortis and the Company in accordance with
their interpretation of the terms of the Merger Agreement.

Project Bonuses.

In January 2016, the Committee approved the final payment of cash bonuses to all
executives, including NEOs, in connection with the Kansas V-Plan project being placed into service. The final Kansas
V-Plan project bonus was paid in February 2016.

2012 Retention Compensation Agreement. Pursuant to a retention compensation arrangement for Mr.
Welch entered into in 2012, he was entitled to be paid cash payments of $1,500,000 on each of June 30, 2014 and
June 30, 2016, if he satisfied continued employment and satisfactory performance conditions as the Company’s
Chief Executive Officer as of such dates. The payments under the agreement were not included in the calculation
of retirement benefits payable to Mr. Welch pursuant to the MSBP. The Committee determined that Mr. Welch met
the “satisfactory performance” standard for purposes of each of the payments.

Long-Term Incentives

Through the closing of the Merger, the Committee provided and maintained a long-term incentive program
under the ITC Holdings Corp. 2015 Long Term Incentive Plan, or 2015 LTIP. With the closing of the Merger, all
outstanding awards under the 2015 LTIP and its terminated predecessor plan, the 2006 LTIP, became vested and
converted into the right to receive cash, per the Merger Agreement, and the 2015 LTIP was then terminated.

In May 2016, the Committee approved grants of restricted stock to employees, including the NEOs, under
the 2015 LTIP based on our CEO’s recommendation, and also on the Committee’s assessment of the performance
of the Company and the executive. Awards to the Chief Executive Officer were also presented to the Board of
Directors by the Committee and ratified by the Board of Directors. The amounts and terms of the 2016 restricted
stock grants made under the 2015 LTIP are described in the narrative following the Grants of Plan-Based Awards
Table.

The awards were designed to reward, motivate and encourage performance, act as a retention mechanism,
and further align the interests of the NEOs with the interests of shareholders. As in past years, total value for the
award for each grantee was determined based on a percentage of salary. For the NEOs, when the May 2016 awards
were made, the award values were targeted to be:

NEO

Ms. Blair
Ms. Holloway
Mr. Jipping
Ms. Mason Soneral
Mr. Oginsky
Mr. Welch
Mr. Hayes

Grant Value
Percent of
Salary

175%
65%
175%
175%
175%
260%
175%

Ms. Holloway’s long-term incentive opportunity represents the target for her role as Vice President, Finance
and Treasurer. In October 2016, the Board, with the recommendation of the Committee, effective for 2017, increased
Ms. Blair’s targeted award from 175% to 250% of annual base compensation in connection with her appointment to
President and Chief Executive Officer, based on market data and in consultation with Fortis. This element of target
compensation is very volatile and can produce significant variances in year-over-year levels, as well as in the actual
value realized, if any, upon completion of the multi-year performance/vesting periods. 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 Chief Executive Officer (with respect to grants other than to the Chief Executive Officer) in
light of comparisons to benchmarking data, expense to the Company and dilution of shareholder value, as well as

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amounts that it believes will motivate performance to achieve continued growth in shareholder value. While options
and performance-based shares had been awarded in recent years, the Committee granted only restricted stock in
2016 in accordance with restrictions in the Merger Agreement. The Board expects to adopt a plan allowing cash
based awards or grants of Fortis stock-based units that settle only in cash beginning in 2017.

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 two supplemental nonqualified, noncontributory retirement benefit
plans for selected management employees: the Management Supplemental Benefit Plan, or MSBP, in which only
Mr. Welch participates and the Executive Supplemental Retirement Plan, or ESRP, in which all other NEOs participate.
These plans provide 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 and, with regard
to the MSBP, changes must generally be agreed to by Mr. Welch. Mr. Welch retired in November 2016. 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.

For Mr. Welch, the Change in Pension Value & Non-Qualified Deferred Compensation Earnings column of
the Summary Compensation Table includes amounts associated with the MSBP. Mr. Welch retired under DTE
Energy’s Management Supplemental Benefit Plan, though with lower benefits than he would have earned with
additional service. In order to compensate Mr. Welch for the value of benefits he would have received had he remained
with DTE Energy, the Company agreed to establish the MSBP such that his retirement benefits would be calculated
to include service with DTE Energy, with the resulting amount offset by the benefits he is receiving from DTE Energy.
The MSBP is described in detail in “Pension Benefits — Management Supplemental Benefit Plan” following the
Pension Benefits Table.

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. While serving as
President and CEO, Mr. Welch and guests who traveled with him were permitted to travel for personal business on
our aircraft, with an annual maximum of 125 flight hours for such personal 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.

Except for Mr. Welch prior to his retirement in November 2016, 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 6 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

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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 and the changes made to the prior agreements.

In addition to severance benefits identified in their employment agreements, pursuant to the Merger
Agreement, all share-based awards vested immediately prior to closing and were converted into the right to receive
cash equal to the value of the Merger consideration.

Recoupment Policy

Our Recoupment Policy provides that in the event of any restatement of financial results, the officer 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 the equity based grants
made after the effective date of the policy and to incentive cash compensation awards made for fiscal years beginning
with 2014.

Welch Letter Agreements

In connection with the Merger Agreement, the Company entered into a letter agreement with Mr. Welch,
dated February 8, 2016, that amended the terms of his employment agreement. Under the terms of the February
8 letter agreement, Mr. Welch’s employment would have become “at-will”, effective as of December 21, 2016.
Following that date, if Mr. Welch’s employment had been terminated for any reason, including his retirement, Mr.
Welch would not have been entitled to any severance payments or benefits under his employment agreement other
than his accrued rights (as defined under his employment agreement), and he would no longer have been subject
to the post-termination covenants set forth in his employment agreement restricting competition and solicitation of
our customers and employees. Additionally, after December 21, 2016, either Mr. Welch or the Company would have
been entitled to select Mr. Welch’s retirement date at any time and for any reason.

Under the February 8 letter agreement, if Mr. Welch’s employment were terminated after December 21,
2016, due to his retirement (other than due to a retirement date selected by us in connection with a cause event),
death or disability, (A) all of his unvested stock options and restricted stock grants would have fully vested upon
termination and (B) with respect to all his unvested performance shares, Mr. Welch would have received, following
the vesting date under the applicable performance shares award agreement, the number of shares to which Mr.
Welch would have otherwise been entitled if he had remained employed through such vesting date. If Mr. Welch
had remained employed at the time cash and equity incentive awards were granted in the ordinary course, the
February 8 letter agreement provided that he would have been entitled to receive cash and equity incentive awards
that were consistent with his employment agreement and commensurate with his role as our Chief Executive Officer.

On October 14, 2016, Mr. Welch notified the Company that he would resign as the Company’s President
and Chief Executive Officer, effective November 1, 2016. In exchange for providing transition services to the Company,
Mr. Welch entered into a letter agreement dated October 14, 2016 that superseded Mr. Welch’s previous agreement
with the Company, dated December 21, 2012, as amended by the February 8 letter agreement. Pursuant to the
October 14 letter agreement, Mr. Welch received a lump sum payment of $1,300,000 in exchange for, among other
items, transition services, waiving his potential right to receive certain post-retirement severance payments under
the employment agreement and a general release of any claims against the Company. Mr. Welch also received all
compensation accrued to him prior to his retirement, including his entire annual corporate performance bonus based

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on target performance through the closing of the Merger and the $250,000 discretionary cash bonus awarded in
May 2016.

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 (other than Mr. Welch) 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 will receive the remaining
70% if they remain employed by the Company through the first anniversary of the effective date (and payments may
be accelerated upon the recipient’s qualifying termination, which includes any termination for which severance would
be payable). The amount of each named executive officer’s potential retention bonus amount is listed below:

NEO

Retention Award

Linda Blair
Gretchen Holloway
Jon Jipping
Daniel Oginsky
Christine Mason Soneral
Joseph Welch
Rejji Hayes

921,000
200,000
753,000
634,500
525,000
—
600,000

Mr. Hayes and Ms. Mason Soneral’s agreements provided for them to receive an additional award in the
amount of $300,000 each if the Merger closed on or before December 31, 2016 and they remained employed by
the Company on the effective date of the Merger. Both conditions were met for each of these NEOs.

Employment Agreement Amendments — Mason Soneral and Hayes

In October 2016, to address cutback language in their employment agreements that could have caused
them to be treated differently than other NEOs, the employment agreements with Ms. Mason Soneral and Mr. Hayes
were amended to (1) have their 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 their
respective employment agreement and the Company’s past practices based on actual 2016 performance; (2) have
a portion of their Company 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 will receive total retention payments of $162,399 payable
in five equal installments to be paid on the first payroll date following the first day of each fiscal quarter beginning
January 1, 2017, contingent on her continued service to the Company or its affiliates on each applicable payment
date. Because Mr. Hayes resigned from his position with the Company as of November 25, 2016, the Company
was not required to pay the annual bonus in February 2017 and will not be required to make the cash installment
payments.

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

BARRY V. PERRY

SANDRA E. PIERCE THOMAS G. STEPHENS

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

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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 ($)
(1)

(c)

Bonus
($) (2)

(d)

Stock Awards
($) (3)

(e)

Option
Awards
($) (3)

(f)

Change in
Pension
Value &
Non-
qualified
Deferred
Compensati
on Earnings
($)(5)

Non-Equity
Incentive
Plan
Compensatio
n ($) (4)

All Other
Compensat
ion ($) (6)

(g)

(h)

(i)

Total ($)

(j)

635,146

659,662

1,074,490

— $

1,244,401

291,249

41,301

$ 3,946,249

616,362

627,515

222,164

131,234

744,344

322,342

342,146

730,851

598,650

706,100

41,875

310,407

37,990

38,588

2,603,531

2,867,037

Year

(b)

2016

2015

2014

2016

210,116

60,000

139,761

2016

2015

2014

2016

2015

2014

503,931

516,623

424,627

430,012

539,333

207,775

137,603

454,458

153,055

86,697

878,517

608,587

263,358

740,250

512,812

222,070

—

279,734

597,533

—

235,714

503,498

168,337

71,163

31,312

680,689

982,615

489,450

577,300

827,980

412,425

486,450

365,553

82,651

455,009

213,915

13,883

234,481

37,269

36,010

36,279

35,497

26,869

25,970

3,307,218

2,208,138

2,583,705

2,696,727

1,779,385

1,989,178

2016

351,346

524,557

612,487

—

695,590

135,364

35,675

2,355,019

2015

2016

2015

2014

2016

2015

2014

328,777

38,861

775,093

195,034

341,250

112,077

13,950

1,805,042

920,076

2,349,042

2,660,821

—

2,013,540

13,310,749

1,575,536

22,829,764

1,027,336

976,180

1,843,228

847,266

1,247,269

4,787,563

377,529

11,106,371

1,012,182

2,314,262

1,862,578

775,648

1,471,138

8,544,075

375,715

16,355,598

374,808

395,192

480,000

—

699,992

854,951

—

222,894

314,800

390,000

28,737

68,429

28,426

31,927

1,926,763

1,963,393

289,092

30,000

50,798

$ 115,175

373,750

82,560

34,370

975,745

Name

(a)

Linda H. Blair,
President &
CEO (7)

Gretchen L.
Holloway
VP, Interim
CFO &
Treasurer (8)

Jon E. Jipping,
EVP & COO

Daniel J.
Oginsky,
EVP & CAO (9)

Christine
Mason Soneral,
SVP & General
Counsel (10)

Joseph L.
Welch, Director
and Former
President &
CEO (11)

Rejji P. Hayes,
Former EVP &
CFO (12)

____________________________

(1)

(2)

The compensation amounts reported in this column include the $20,000 lump sum cash payments made to
Ms. Blair, Mr. Jipping and Mr. Oginsky in 2014.

The compensation amounts reported in this column include, (a) awards under the Special Bonus Plan, (b)
bonuses paid in connection with project milestones, efforts related to the proposed Entergy transaction and
completion of the Merger, (c) retention bonuses and (d) a discretionary cash bonus made to Mr. Welch in
2016. 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 each
year, the NEOs, except for Mr. Hayes, received certain project-related bonuses in recognition of the successful
completion of various transmission development milestones. In 2014, while Mr. Hayes served in his prior
position as our Vice President Finance and Treasurer, he received a cash bonus in recognition of the integral
role he played in the Company’s pursuit of the transmission business of Entergy Corporation. On May 19,
2016, the Committee approved a discretionary cash bonus to Mr. Welch in the amount of $250,000 which
was to be paid at the same time as the payment of the 2016 annual corporate performance bonus. This
amount was included in the payment made pursuant to Mr. Welch’s October 2016 letter agreement. These
bonuses are set forth in the following table under Other Bonuses. Mr. Hayes and Ms. Mason Soneral received
$300,000 each since the Merger was closed before December 31, 2016. In 2014 and 2016, Mr. Welch
received a bonus pursuant to his Retention Compensation Agreement. In 2016, all of the NEOs (other than
Mr. Welch) received 30% of their retention award due to the closing of the Merger. See “Compensation

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Discussion and Analysis — Retention Program”. The remainder of the Merger-related bonuses will become
earned in 2017 but only if the NEOs remain employed by the Company on the one-year anniversary of the
closing of the Merger.

Name

Year

Special
Bonus ($)

Retention
Bonus ($)

Merger
Completion
($)

Other
Bonuses ($)

Total Bonus
($)

— $

276,300

— $

383,362

659,662

Linda H.
Blair

Gretchen L.
Holloway

Jon E.
Jipping

Daniel J.
Oginsky

Christine
Mason
Soneral

Joseph L.
Welch

Rejji P.
Hayes

2016

2015

2014

2016

2015
2014

2016

2015

2014

2016

2015

2016

2015
2014

2016

2015

2014

—

22,919

—

26,136
49,055

—

13,115

—

313,627
588,654

—

— $

—

60,000

225,900

—
—

190,350

—

—
—

—

157,500

300,000

—

1,500,000

—
1,500,000

180,000

—

— $

—

—
—

300,000

—

222,164

108,315

—

313,433

181,639
88,548

264,108

153,055

73,582

67,057

38,861

849,042

662,553
225,608

—

222,164

131,234

60,000

539,333

207,775
137,603

454,458

153,055

86,697

524,557

38,861

2,349,042

976,180
2,314,262

480,000

—

— $

30,000

(3)

The amounts reported in these columns represent the fair value of stock option, performance share and
restricted stock awards granted to the NEOs under the 2015 LTIP and the 2006 LTIP, excluding any forfeiture
reserves recorded for these awards. Restricted stock awards are recorded at fair value at the date of grant,
which is equivalent to the share price on that date. In accordance with Financial Accounting Standards Board
Accounting Standards Codification 718, or ASC 718, the fair value of the performance share awards with
the three-year relative TSR metric was determined using a Monte Carlo simulation valuation model and the
fair value of the performance shares with the three-year Diluted EPS Growth metric was based on the share
price on the date of grant. The grant date present value of the stock options was determined in accordance
with ASC 718 using a Black-Scholes option pricing model and the following assumptions:

Remaining
Future Life of
Option

Expected
Volatility

Risk Free
Interest Rate

Expected
Life (Years)

Expected
Dividend
Yield

Share Price at
Grant Date

—

9.3

8.3

—%

18.6%

27.2%

—%

1.81%

1.8%

—

—% $

1.59% $

1.55% $

—

35.91

36.73

Year

2016

2015

2014

(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 2016, 2015 and 2014. For information regarding
the corporate goals for 2016, see “Compensation Discussion and Analysis — Key Components of Our NEO
Compensation Program — Bonus Compensation".

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In October 2016, cash awards tied to our 2016 annual corporate performance bonus plan were prorated
based on the effective date of the Merger and paid out at 200% of “target bonus levels,” which was jointly
determined by Fortis and the Company to constitute “target” as used in the Merger Agreement. For the
period following the effective date of the Merger, the cash awards were paid out at actual performance
against the 2016 performance goals (180% of “target bonus levels”) and prorated for the balance of the year.
The cash payments are set forth in the following table.

Name

Pre-Merger

Post-Merger

Linda H. Blair

Gretchen L. Holloway

Jon E. Jipping

Daniel J. Oginsky

Christine Mason Soneral

Joseph L. Welch

Rejji P. Hayes

966,436 $

135,364

790,148

665,802

275,450

2,013,540

314,800 $

277,965
32,972

192,467

162,178

420,140

—

____________________________

(a) To address cutback language in their employment agreements that could have caused them to be
treated differently than the other NEOs, the employment agreements with Ms. Mason Soneral and Mr.
Hayes were amended to have their annual bonus for 2016 (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 their respective employment agreement and the Company’s past
practices based on actual 2016 performance. Because Mr. Hayes resigned from his position with the
Company as of November 25, 2016, the Company was not required to pay to him the post-Merger
portion of the annual corporate performance bonus in February 2017 to which he would otherwise
have been entitled.

(b)

In connection with Mr. Welch’s retirement, he received all of his 2016 annual corporate performance
bonus in 2016.

All amounts reported in this column pertain to the tax-qualified defined benefit pension plan and two
supplemental nonqualified, noncontributory retirement plans 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 4.05% in 2014, 4.44%
in 2015 and 4.15% in 2016 causing the amounts to fluctuate down from 2014 to 2015 and back up in 2016.
Mr. Welch’s change in pension value increased most significantly due to the year over year change in his
MSBP benefit which increased due to an additional 15 months of service and higher average final
compensation, along with one less year of discounting as he retired during 2016.

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, home
security system, 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, as well as
any reimbursements for income taxes related to the inclusion of the value of the payment by the Company
of these perquisites and payments associated with Mr. Welch’s retirement. 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 Mr. Welch’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. Mr. Welch received a
lump sum severance payment of $1,300,000, made pursuant to his October 2016 letter agreement in
exchange for, among other items, transition services, waiving his potential right to receive certain post-
retirement severance payments under the employment agreement and a general release of any claims

(5)

(6)

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against the Company. Director compensation relates to compensation Mr. Welch received for his service
as chairman and director after his retirement. Mr. Welch remained on the Board and became a non-employee
director upon his retirement on November 1, 2017. These benefits and perquisites for 2016, 2015 and 2014
are itemized in the table below as required by applicable SEC rules.

Name

Linda H.
Blair

Gretchen L.
Holloway

Jon E.
Jipping

Daniel J.
Oginsky

Christine
Mason
Soneral

Joseph L.
Welch

Rejji P.
Hayes

401(k)
Match

Tax
Reimbursements

Personal
Use of
Company
Aircraft

Other
Retirement
Compensation

Director
Compensation

Other
Benefits

Total

$ 14,300

— $

27,001

41,301

14,300

13,950

14,300

15,900

14,300

13,950

14,300

13,950

14,300

13,950

15,900

—

23,690

24,638

17,012

21,369

21,710

22,329

21,197

12,569

12,020

21,375

—

37,990

38,588

31,312

37,269

36,010

36,279

35,497

26,869

25,970

35,675

13,950

72,955

125,141

1,300,000

24,865

36,675

1,575,536

Year

2016

2015

2014

2016

2015

2014

2016

2015

2014

2016

2015

2016

2015

15,900

157,704

160,025

2014

2016

2015

2014

15,600

14,300

156,386

164,476

—

$ 13,950

— $

—

43,900

377,529

39,253

14,126

17,627

375,715

28,426

31,927

— $

20,420

34,370

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.

The All Other Compensation column does not include payments made for purposes of settling outstanding
options and share-based awards at the closing of the Merger as described under “Compensation Discussion
and Analysis — Merger Agreement and the Merger.” For a description of the amounts paid, see “Option
Exercises and Stock Vested.”

(7)

(8)

Ms. Blair became President and Chief Executive Officer in November 2016.

Ms. Holloway became Vice President, Interim Chief Financial Officer and Treasurer in October 2016. In
accordance with SEC rules, we have excluded Ms. Holloway’s compensation for 2014 and 2015 as she was
not an executive officer in those years.

(9)

Mr. Oginsky was named Executive Vice President and Chief Administrative Officer in May 2016.

(10) Ms. Mason Soneral became Senior Vice President and General Counsel in February 2015. In accordance
with SEC rules, we have excluded Ms. Mason Soneral’s compensation for 2014 as she was not an executive
officer in that year.

(11) Mr. Welch retired from the Company in November 2016. Mr. Welch remains a director and serves as Chairman

of the Company’s Board of Directors.

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(12)

In May 2016, Mr. Hayes was named Executive Vice President and Chief Financial Officer. Mr. Hayes left the
Company in November 2016.

Grants of Plan-Based Awards

The following table sets forth information concerning each grant of an award made to a NEO during 2016.

Grants of Plan-Based Awards Table

Name

(a)

Linda H. Blair

Gretchen L. Holloway

Jon E. Jipping

Daniel J. Oginsky

Christine Mason Soneral

Joseph L. Welch

Rejji P. Hayes

Estimated Future Payouts Under Non-
Equity Incentive Plan Awards

Grant Date

Threshold
($)

Target ($)
(1)

Maximum
($)(1)

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

Grant Date Fair Value of
Stock and Option Awards ($)
(2)

(b)

(c)

(d)

(e)

(i)

(j)

5/19/2016

— $

24,448

1,074,490

5/19/2016

—

725,000

1,450,000

—

86,000

172,000

—

502,000

1,004,000

—

423,000

846,000

—

350,000

700,000

—

1,279,250

2,558,500

—

$ 400,000

800,000

—

3,180

—

19,989

—

16,843

—

13,936

—

60,542

—

15,927

— $

—

139,761

—

878,517

—

740,250

—

612,487

—

2,660,821

—

699,992

—

____________________________

(1)

The amount shown in Column (d) represents the potential payout for the annual corporate performance
bonus based on “target bonus levels” and assumes maximum achievement of all bonus goals other than
the TSR goal and no achievement of the TSR goal. The amount payable assuming maximum achievement
of all 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 — Bonus Compensation — Annual Corporate Performance Bonus.”

(2)

Grant Date Fair Value consists of restricted stock awarded under the 2015 LTIP, recorded at fair value at
the date of grant, which was $43.95 per share.

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

The Committee had the power to grant stock options, restricted stock, restricted stock units and performance
based awards in the form of equity or cash under the 2015 LTIP with the terms of each award set forth in a written
agreement with the recipient. Equity-based grants made in 2016 to the NEOs were made under the 2015 LTIP
pursuant to terms stated in a restricted stock award agreement.

The 2016 restricted stock award agreements provided that, subject to the Merger Agreement, so long as
the grantee remains employed by us, the restricted stock fully vests upon the earlier of (i) the third anniversary of
the grant date (ii) the grantee's death or permanent disability, or (iii) the occurrence of a “Change in Control

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Termination” (as defined in the 2015 LTIP). If the Merger occurred, the restricted stock would immediately vest, and
would be cancelled and converted into the right to receive an amount in cash equal to the product of (x) the total
number of shares subject to such restricted stock award multiplied by (y) the cash value of the Merger consideration
(later determined to be $45.72), as provided in Section 2.2(b) of the Merger Agreement. If the Merger did not occur
and employment was terminated prior to the vesting date for any reason other than death, disability, Retirement (as
defined in the 2015 LTIP) or Change in Control Termination, the remaining unvested shares would be canceled
unless the Committee, in the exercise of its authority under the 2015 LTIP, modified the vesting date in connection
with the termination. If the grantee attained age 65 prior to the vesting date while continuing to be employed by the
Company, the stock would have become vested (i) as of the date the grantee becomes 65, in increments of 33-1/3%
of such shares in respect of each one year anniversary (if any) of the date of the grant agreement that occurred prior
to the grantee attaining such age, and (ii) in increments of 33-1/3% of such shares as of each one year anniversary
of the date of the agreement that occurred after the grantee attained such age until all shares have fully vested
(provided that grantee continues to be employed by the Company as of each such anniversary). The restricted stock
award agreements also provided that restricted stock issued to the grantee generally could not be transferred by
the grantee prior to vesting and that grantees otherwise had all rights of holders of our common stock.

Outstanding Equity Awards at Fiscal Year-End

The NEOs did not have any outstanding equity awards as of December 31, 2016. Pursuant to the Merger
Agreement, all outstanding stock option, restricted stock and performance share awards vested and were cashed
out as of immediately prior to the effective date of the Merger. Please see “Compensation Discussion and Analysis
— Merger Agreement” for further details.

Option Exercises and Stock Vested

The following table provides information with respect to options exercised by the NEOs during 2016 and
shares of restricted stock and performance shares held by the NEOs that vested during 2016. The table also includes
amounts paid by the Company pursuant to the Merger Agreement to cash out options, restricted stock and
performance shares held immediately prior to the effective time of the Merger.

Option Exercises and Stock Vested Table

Name

(a)

Linda H. Blair

Gretchen L. Holloway

Jon E. Jipping

Daniel J. Oginsky

Christine Mason Soneral (4)

Joseph L. Welch

Rejji P. Hayes (4)

Option Awards (3)

Stock Awards (3)

Number of Shares Acquired
on Exercise (#)

Value Realized on
Exercise ($) (1)

Number of Shares
Acquired on
Vesting (#)

Value Realized on
Vesting ($) (2)

(b)

(c)

(d)

(e)

737,800

16,157,448

80,138

3,648,382

11,977

556,283

330,649

57,884

859,844

840,131

11,730,528

6,125,131

1,167,080

17,817,645

13,482

54,396

53,826

44,179

204,674

65,744

739,895

41,858

615,474

2,982,761

2,452,260

2,017,404

9,289,702

3,702,669

____________________________

(1) Equals the stock price on the NYSE on the exercise date minus the option exercise price multiplied by

the number of shares acquired on exercise.

(2) Equals the stock price on the NYSE on the vesting date multiplied by the number of shares acquired

on vesting.

(3) The table below reflects the amounts paid to cash out outstanding equity awards in accordance with
the Merger Agreement. All unvested options, restricted shares and performance shares became vested
immediately prior to the effective time of the Merger pursuant to the Merger Agreement. Options were
cashed out at the difference between $45.72 (the cash value of the Merger consideration paid to

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shareholders) and the option exercise price. Restricted stock and performance shares were cashed
out at $45.72 per share.

Name

(a)

Linda H. Blair

Gretchen L. Holloway

Jon E. Jipping

Daniel J. Oginsky

Christine Mason Soneral

Joseph L. Welch

Rejji P. Hayes

Option Awards

Stock Awards

Number of Shares (#)

Value Realized ($)

Number of Shares
(#)

Value Realized($)

(b)

(c)

(d)

(e)

710,554

15,248,633

69,551

3,179,907

5,284

556,283

330,649

20,734

836,570

51,243

11,730,528

6,125,131

709,209

17,051,737

12,846

45,744

47,916

42,517

162,463

65,744

739,895

40,262

587,331

2,599,910

2,190,742

1,943,860

7,427,826

1,840,793

(4) To address cutback language in the employment agreements of Ms. Mason Soneral and Mr. Hayes, the
agreements were amended, pursuant to which a portion of their performance shares were canceled.
Ms. Mason Soneral’s amendment provided that she will receive total retention payments of $162,399
payable in five equal installments to be paid on the first payroll date following the first day of each fiscal
quarter beginning January 1, 2017, contingent on her continued service to the Company or its affiliates
on each applicable payment date. Mr. Hayes’ agreement contained a similar provision but his right to
such payments was forfeited upon his resignation from the Company.

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”), the MSBP and the ESRP.

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Pension Benefits Table

Name

(a)

Plan Name

(b)

Cash Balance Component

Linda H. Blair

ESRP Shift

Total Qualified Plan

ESRP

Cash Balance Component

Gretchen Holloway

Total Qualified Plan

ESRP

Traditional Component

Jon E. Jipping

Total Qualified Plan

ESRP

Cash Balance Component

Daniel J. Oginsky

Total Qualified Plan

Christine Mason
Soneral

ESRP

Cash Balance Component

Total Qualified Plan

ESRP

Cash Balance Component

Number of Years
Credited Service (#)
(1)

Present Value of
Accumulated
Benefit ($)(2)

Payments During
Last Fiscal Year
($)

(c)

(d)

(e)

22.58

N/A

13.82

12.95

1.91

26.03

11.92

12.20

12.00

9.29

9.28

N/A

329,464

33,974

363,438

1,236,657

195,764

60,112

1,190,011

1,078,432

254,691

823,419

194,003

366,614

N/A

1,588,184

48,117,216

99,755

163,303

N/A

287,900

21,685

309,585

N/A

Joseph L. Welch

Special Annuity Credit

10.00 (3)

Rejji P. Hayes

Total Qualified Plan

MSBP

Cash Balance Component

Total Qualified Plan

ESRP

____________________________

46.00

4.86

(1) Credited service is estimated as of December 31, 2016 and represents the service reflected in the
determination of benefits. For determining vesting, service with DTE Energy is counted for all plans shown
in the table except for the ESRP, as explained below.

For Ms. Blair and Mr. Jipping, the credited service for the traditional and cash balance components of the
Qualified Plan includes service with DTE Energy. The Company began operations on February 28, 2003,
following its acquisition of ITCTransmission from DTE Energy. As of that date, the benefits from DTE Energy’s
qualified plan that had accrued, as well as the associated assets from DTE Energy’s pension trust, were
transferred to the Company’s 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.

Mr. Welch’s credited service for the Qualified Plan only includes service with the Company because he
retired under DTE Energy’s qualified plan concurrent with commencing employment with the Company. As
a result, unlike the other NEOs, his benefits under DTE Energy’s qualified plan were not transferred to the
Qualified Plan. Mr. Welch also retired under DTE Energy’s Management Supplemental Benefit Plan, though
with lower benefits than he would have earned with additional service. In order to compensate Mr. Welch
for the value of benefits he would have received had he remained with DTE Energy, the Company agreed
to establish its MSBP such that benefits would be calculated including service with DTE Energy, with the

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resulting amount offset by the benefits he is receiving from DTE Energy. We estimate that $6.6 million of
the Present Value of Accumulated Benefit is the value of the augmentation of benefits resulting from including
Mr. Welch’s 32 years of service with DTE Energy.

(2) The “Present Value of Accumulated Benefit” is the estimated lump-sum equivalent value measured as of
December 31, 2016 (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, 2016. The rate at which future expected
benefit payments were discounted in calculating present values was 4.15%, the same rate used for fiscal
year-end 2016 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 2.35% for 2017 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
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. Blair:

Age 58

Ms. Holloway

Age 58

Mr. Jipping:

Age 58

Mr. Oginsky

Age 58

Ms. Mason Soneral Age 58

Mr. Welch:

Actual retirement was November 1, 2016

Mr. Hayes

Age 58 for the qualified plan and June 1, 2017 for the ESRP

Post-retirement mortality was assumed to be in accordance with the RP-2014 table projected for future
mortality improvements with modified MP-2014 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.
Under the MSBP, benefits are payable for Mr. Welch’s life with a minimum payment period of 15 years
guaranteed. For all other benefits, payment was assumed to be as a single lump sum, although other
actuarially equivalent forms are available.

(3) A maximum of 10 years of service is counted for purposes of the Special Annuity Credit.

We maintain one tax-qualified noncontributory defined benefit pension plan and two supplemental
nonqualified, noncontributory defined benefit retirement plans. 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.

Second, we maintain the MSBP, in which Mr. Welch is the only participant. The MSBP provides additional

retirement benefits that are not tax-qualified.

Third, we maintain the ESRP, in which Mses. Blair, Holloway and Mason Soneral and Messrs. Hayes, Jipping

and Oginsky participate. The ESRP provides additional retirement benefits which are not tax qualified.

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The following describes the Qualified Plan, the MSBP, 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. Mr. Welch began receiving retirement benefits under the traditional
component of the DTE Plan before beginning his employment with us, and is earning benefits under the cash balance
component of the Qualified Plan. In addition to the traditional and cash balance components, Mr. Welch has earned
a special annuity credit described below, and Ms. Blair has benefits under the ESRP shift, also described below.

Benefits under the Qualified Plan are funded by an irrevocable tax-exempt trust. A NEO’s benefit under the

Qualified Plan is payable from the assets held by the tax-exempt trust.

NEOs become fully vested in their normal retirement benefits described below with 3 years of service,
including service with DTE Energy, or upon attainment of the plan’s normal retirement age of 65. If a NEO terminates
employment with less than 3 years of service, the NEO is not vested in any portion of his or her benefit.

Traditional Component of Qualified Plan

Mr. Jipping participates in the traditional component of the Qualified Plan. The benefits are determined under
the following formula, stated as an annual single life annuity payable in equal monthly installments at the normal
retirement age of 65: 1.5% times average final compensation times credited service up to 30 years, plus 1.4% times
average final compensation times credited service in excess of 30 years. Credited service includes service with DTE
Energy. Although benefits under the formula are defined in terms of a single life annuity, other annuity forms (e.g.,
joint and survivor benefits) are available that have the same actuarial value as the single life annuity benefit. The
benefits are not payable in the form of a lump sum.

Average final compensation is equal to one-fifth of the NEO’s salary (excluding any bonuses or special pay)
during the 260 weeks of credited service, not necessarily consecutive, at any time during the NEO’s employment
that results in the highest average.

Benefits provided under the Qualified Plan are based on compensation up to a compensation limit under
the Internal Revenue Code (which was $265,000 in 2016, 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
$210,000 payable as a single life annuity beginning at normal retirement age in 2016).

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:

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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 $101,100. He is fully vested.

Cash Balance Component of Qualified Plan

Mses. Blair, Holloway and Mason Soneral and Messrs. Welch, Hayes and 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 ($265,000 in 2016). 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. Blair, 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. Blair’s estimated account value as
of year-end 2016 is approximately $324,000, Ms. Holloway’s is approximately $190,000, Ms. Mason Soneral’s is
approximately $189,000, and Mr. Oginsky’s is approximately $248,000. Mr. Welch received a lump sum payment
of the full value of his account $287,900 upon his retirement in November 2016. Mr. Hayes is fully vested in the
Cash Balance Plan and has not commenced his benefit. The estimated account value at year-end 2016 was $99,755.

Special Annuity Credit for Mr. Welch in the Qualified Plan

In addition to his cash balance account, Mr. Welch has earned an additional benefit in the Qualified Plan.
This benefit is stated as a single life annuity payable in equal monthly installments, equal to $10,000 times years of
credited service after February 28, 2003 up to ten years of credited service (i.e., the maximum benefit is $100,000
per year commencing at normal retirement age). Other annuity forms are available that are actuarially equivalent to
the single life annuity.

Because Qualified Plan benefits are offset against the otherwise determined MSBP benefits (see below),
the effect of this benefit is to shift benefits from the MSBP, a nonqualified plan, to the Qualified Plan, which affords
certain tax benefits to the Company and Mr. Welch. As of year-end 2013, Mr. Welch was eligible to retire and receive
the maximum annual benefit of $100,000 commencing at normal retirement age. Mr. Welch has commenced this
benefit upon his retirement in the form of a Single Life Annuity with an annual benefit of $130,100 reflecting an
actuarial increase from the normal retirement age to his actual retirement age.

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ESRP Shift Benefit in Qualified Plan

The ESRP provides notional account accruals similar to the cash balance component of the Qualified Plan.
The “compensation credit” to the NEO’s notional account, analogous to the contribution credit in the cash balance
component of the Qualified Plan, is equal to 9% of base salary plus actual bonus earned under the Company’s
annual bonus plan. The “investment credit,” analogous to the interest credit in the cash balance component of the
Qualified Plan, is similarly based on 30-year Treasury rates.

The ESRP shift benefit is an amount that would otherwise be payable from the ESRP, but is instead being
paid from the Qualified Plan, subject to applicable qualified plan legal limits on the ability to discriminate in favor of
highly paid employees. The NEO’s cash balance account is increased by any amounts shifted from the ESRP. As
with Mr. Welch’s special annuity credit, the purpose of the benefit is to provide the NEOs and the Company the tax
advantages of providing benefits through a qualified plan.

Ms. Blair has received ESRP shift additions to her Qualified Plan cash balance account. There was no shift
of compensation credits for 2016, although previous shifts have continued to earn interest credits. As of year-end
2016, her ESRP shift balance was approximately $33,000.

Management Supplemental Benefit Plan

The benefit provided by the MSBP to Mr. Welch is payable as an annuity beginning on the earliest date
following termination of employment that is permitted under Section 409A of the Internal Revenue Code (relating to
the taxation of deferred compensation). The purpose of the MSBP is to provide an overall target level of benefits
based on all of Mr. Welch’s years of service, including with DTE Energy. The MSBP benefit is equal to this overall
target offset by all of Mr. Welch’s benefits earned under the Qualified Plan, the DTE Plan, and DTE Energy’s
Management Supplemental Benefit Plan, a nonqualified plan.

The MSBP target before offsets, expressed as an annual single life annuity with 15 years of payments
guaranteed commencing at age 60 (the MSBP normal retirement age) or later, is equal to: (1) 60% plus 0.5% for
each year of total service in excess of 25 years, times (2) “average final compensation.”

Mr. Welch commenced his MSBP benefit on November 1, 2016 with the first six months of payment delayed
until May 2, 2017. The life annuity with 15 years of guaranteed payments is the only form of benefits payable under
the plan. A lump sum is not available.

“Average final compensation” is equal to one-fifth of Mr. Welch’s compensation during the 260 weeks, not
necessarily consecutive, of Company service that results in the highest average. Compensation is equal to salary
plus any bonuses, excluding Special Bonus Amounts paid after May 17, 2006 under the Special Bonus Plan and
amounts paid under Mr. Welch’s retention compensation agreement. Unlike the Qualified Plan, for the MSBP there
is no limit on the amount of pay taken into account.

For purposes of calculating average final compensation, amounts paid by DTE Energy are considered in
selecting the highest 260 weeks. Further, each bonus payment that is considered compensation is mapped to the
single week it was paid before the highest 260 weeks are selected. Therefore, although compensation is averaged
over the number of weeks in 5 years, the average final compensation includes well over 5 years of bonuses.

As of December 31, 2016, Mr. Welch has retired, and he will receive an annual MSBP benefit of approximately
$3,486,000 after offsets, payable as an annuity for his lifetime with a minimum payment period of 15 years guaranteed.

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

Executive Supplemental Retirement Plan

The ESRP is a nonqualified retirement plan. Only selected executives participate, including Mses. Blair,
Mason Soneral, and Holloway, and Messrs. Hayes, Jipping, and Oginsky. Mr. Welch does not participate. 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.

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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 bonuses under the Company’s annual 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.
Mses. Blair, Mason Soneral, and Holloway, and Messrs. Jipping and Oginsky are fully vested. Pursuant to the terms
of the plan, Mr. Hayes became fully vested at the time of the Merger. The benefit provided by the ESRP to Mr. Hayes
is payable as a lump sum beginning on March 1 of the year following termination, but actual payment will be delayed
until June 1, 2017 as required under Code Section 409A.

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, 2016, the ESRP account values, net of the amounts shifted
to the Qualified Plan, are as follows:

Ms. Blair

Ms. Holloway

Mr. Jipping

Mr. Oginsky

Ms. Mason Soneral

Mr. Hayes

1,216,887

58,200

1,074,927

801,021

357,141

164,494

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 and
Mr. Welch is the only NEO who has deferred income under this plan. NEOs are allowed to defer up to 100% of their
salary, bonus and restricted stock dividends. 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. The following table provides information with respect to the plan that
allows for the deferral of compensation on a basis that is not tax-qualified. There were no Company contributions,
or any NEO contributions, withdrawals, or other distributions pursuant to the plan during 2016.

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Nonqualified Deferred Compensation Table

Name

(a)

Aggregate Earnings
in Last FY ($)

Aggregate Balance at
Last FYE ($)

(d)

(f)

Linda H. Blair

Gretchen L. Holloway

Jon E. Jipping

Daniel J. Oginsky

Christine Mason
Soneral

—

Joseph L. Welch (1)

Rejji P. Hayes

48,464

—

777,679

—

____________________________

(1) None of this amount is reported in the Summary Compensation Table, as none of it is above-market or

preferential.

Employment Agreements and Potential Payments Upon Termination or Change in Control

Employment Agreements

As referenced above, we entered into employment agreements with Ms. Blair and Messrs. Jipping, Oginsky
and Welch in December 2012 which superseded the employment agreements then in effect. We entered into an
employment agreement with Mr. Hayes in October 2014. In February 2015, we entered into employment agreements
with Mses. Mason Soneral and Holloway, which in the case of Ms. Mason Soneral, superseded her employment
agreement then in effect. The employment agreements are 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. Blair’s agreement was modified in October 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 and Hayes.” Mr. Welch’s agreement was superseded upon his execution
of the letter agreement with the Company dated October 14, 2016. Mr. Hayes’ agreement was modified in October
2016 and terminated upon his resignation on November 25, 2016. The following describes the material terms of the
employment agreements, as amended, with the NEOs who remained employed by the Company on December 31,
2016.

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

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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. Blair: 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 (one year for Ms. Holloway);

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 and for Ms. Holloway, continued payment of base salary for an additional year;

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;

eligibility to continue coverage under our active medical, dental and vision plans subject to applicable COBRA
rules; if such coverage is elected, we will reimburse the NEO for the shorter of 18 months (12 months for
Ms. Holloway), 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. Blair, 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 (other than Ms. Holloway) will be subject to certain
covenants not to compete with or assist other entities in competing with our business and not to encourage our

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employees to terminate their employment with us. Ms. Holloway would be subject to these covenants for a period
of one year, regardless of the reason for termination of employment, which period may be extended for one additional
year at our sole discretion in exchange for continued payment of Ms. Holloway’s base salary during such period. 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 Made in Connection with the Merger

The table below provides a summary of the payments made to the NEOs as a result of the completion of the Merger.

ITC Holdings
Payments Made in Connection with the Merger
12/31/2016

Linda H.
Blair

Jon E.
Jipping

Daniel J.
Oginsky

Christine
Mason
Soneral

Gretchen L.
Holloway

Joseph L.
Welch

Rejji P.
Hayes

Compensation

Cash Severance

— $

—

Target Short-term
Bonus
Pro Rata Short-term
(Annual) Incentive
Comp(1)

966,436

790,148

665,802

275,450

135,364

2,013,540

314,800

Retention Awards(2)

276,300

225,900

190,350

457,500

60,000

—

480,000

Stock Options(3)

15,248,633

11,730,528

6,125,131

250,706

51,243

17,051,737

1,176,938

Restricted Stock
Awards(3)
Performance Shares
(4)

Benefits and
Perquisites

Retirement Plan

ESRP(5)

Perquisites

Health & Welfare
Benefits

Postretirement
Welfare Plan

Total Payout:

1,387,318

1,134,264

955,753

790,804

167,850

3,435,372

903,727

1,792,590

1,465,646

1,234,989

1,315,456

419,481

3,992,453

1,733,748

—

15,683

—

31,956

$ 19,671,277

$ 15,346,486

9,172,025

3,089,916

849,621

$ 26,493,102

4,641,169

________________________

(1) Reflects pro rata annual bonus payment made in connection with the Merger for the period through October 14,
2016. Remaining annual bonus payments were made at the time that normal annual bonus payments are made
and are not included in this table. Ms. Mason Soneral’s and Mr. Hayes’ annual bonus (with the exception of the
total shareholder return component which was paid out pursuant to the terms of the Merger Agreement) was
payable in the ordinary course in accordance with their respective employment agreement and the Company’s
past practices based on actual 2016 performance. See “Employment Agreement Amendments — Mason Soneral
and Hayes”. Mr. Welch’s amount represents the full amount of his annual corporate performance bonus.

(2) For all but Mr. Hayes, includes 100% of retention bonus, 30% of which was paid in 2016 and the remainder of
which is due one year after closing subject to the NEO’s continued employment. For Mr. Hayes, the amount
shown is the portion he received prior to his resignation. Table also includes $300,000 bonuses paid in 2016 to

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Ms. Mason Soneral and Mr. Hayes that were contingent on closing the Merger prior to December 31, 2016 and
continued employment at the time of the Merger.

(3) Reflects the cash value paid for outstanding stock options and previously unvested restricted stock awards. The
per share amount of the Merger consideration used for purposes of determining the payment amount was $45.72.

(4) Reflects the cash value paid to holders of previously unvested performance share awards in connection with
the Merger. Performance shares vested at 181.25% of target in accordance with the Merger Agreement, together
with related dividend equivalents. The per share amount of Merger consideration used for purposes of determining
the payment amount was $45.72.

(5) Reflects the value of the accelerated vesting ESRP account balance in connection with the Merger.

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, 2016. There was no outstanding
equity as of December 31, 2016.

Linda H. Blair - 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

$ 2,855,674

— $

—

725,000

1,244,401

—

644,700

—

25,000

29,524

25,000

29,524

265,819

—

— $

3,659,444

$ 5,065,118

$ 1,369,700

1,369,700

Compensation

Cash Severance

Target Short-term Bonus

Pro Rata Short-term (Annual)
Incentive Comp

Retention Awards

Stock Options

Restricted Stock Awards

Performance Share Awards

Benefits and Perquisites

Retirement Plan

ESRP

Perquisites

Health & Welfare Benefits

Postretirement Welfare Plan (5)

Total Payout:

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Compensation

Cash Severance

Target Short-term Bonus

Pro Rata Short-term (Annual)
Incentive Comp

Retention Awards

Stock Options

Restricted Stock Awards

Performance Share Awards

Benefits and Perquisites

Retirement Plan

ESRP

Perquisites

Health & Welfare Benefits

Total Payout:

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)

— $

215,000

528,342

— $

—

86,000

168,337

140,000

168,337

140,000

—

140,000

—

25,000

18,172

25,000

18,172

—

86,000

—

140,000

—

— $

566,509

879,851

$ 226,000

226,000

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)

Compensation

Cash Severance

— $

1,004,000

2,153,087

— $

—

Target Short-term Bonus

Pro Rata Short-term
(Annual) Incentive Comp

Retention Awards

Stock Options

Restricted Stock Awards

Performance Share
Awards

Benefits and Perquisites

Retirement Plan (6)

ESRP

Perquisites

Health & Welfare
Benefits

Total Payout:

—

502,000

982,615

527,100

982,615

527,100

—

527,100

—

25,000

28,630

—

25,000

28,630

—

— $

2,567,346

3,716,433

$1,029,100

$ 1,029,100

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Daniel J. Oginsky - 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-
retiremen
t)(4)

Compensation

Cash Severance

Target Short-term Bonus

Pro Rata Short-term (Annual) Incentive
Comp

Retention Awards

Stock Options

Restricted Stock Awards

Performance Share Awards

Benefits and Perquisites

Retirement Plan

ESRP

Perquisites

Health & Welfare Benefits

Total Payout:

— $

846,000

$ 1,794,317

— $

—

— $

423,000

$423,000

— $

827,981

—

444,150

—

— $

25,000

27,737

25,000

27,737

—

— $ 2,170,868

$ 3,119,185

867,150

$867,150

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)

— $

700,000

1,030,674

— $

—

— $ 350,000

350,000

695,590

367,500

695,590

367,500

—

367,500

—

367,500

—

— $

(97,635)

—

25,000

28,511

—

25,000

28,511

—

— $

1,816,601

2,049,639

$ 717,500

717,500

Compensation

Cash Severance

Target Short-term Bonus

Pro Rata Short-term
(Annual) Incentive Comp

Retention Awards

Stock Options

Restricted Stock Awards

Performance Share
Awards

280G Cutback

Benefits and Perquisites

Retirement Plan

ESRP

Perquisites

Health & Welfare Benefits

Total Payout:

____________________________

(1) All scenarios include the value of severance. Table reflect the remaining 70% of the May 2016 retention
program awards under the applicable qualified termination scenarios. There was no outstanding equity as
of December 31, 2016. For Ms. Blair, 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 footnotes (4) and (6), and additional pension
benefits upon death, have not been included in these termination scenarios but can be found in the Pension
Benefits Table.

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(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 safe harbor value where this is
greater than if an excise tax had been paid. Ms. Mason Soneral would be subject to an excise tax at the
assumed change in control date; therefore, a cutback in the amount of $97,635 has been reflected. The
rate at which future expected benefit payments were discounted in calculating the Postretirement Welfare
Plan present values was 4.28%, the same rate used for fiscal year-end 2016 accounting disclosure of the
Postretirement Welfare Plan.

(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, 2016. Under termination for death (pre-retirement), Ms. Blair’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 or estate. The above termination scenarios
do not reflect the reduction in present value of death benefits ($383,208 for Ms. Blair, $666,800 for Mr.
Jipping, $29,326 for Mr. Oginsky, $14,487 for Ms. Mason Soneral, and $8,140 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. Blair'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.

(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,
2016. The above table does not reflect the reduction in the present value ($119,001 except for death) due
to applying the 90% early retirement factor.

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.

Pursuant to his October 2016 letter agreement, Mr. Welch received a lump sum payment of $1,300,000 in
exchange for, among other items, transition services, waiving his potential right to receive certain post-retirement
severance payments under the employment agreement and a general release of any claims against the Company
reflected under Cash Severance. In addition, upon termination Mr. Welch received all benefits that were accrued
but unpaid, which included the May 2016 bonus. Mr. Welch was retirement eligible at the time of his Voluntary
Resignation and therefore is entitled to receive the benefits disclosed in the Pension Benefits Table. Mr. Welch
received a lump sum distribution of his Retirement Plan — Cash Balance Component benefit in November 2016 in
the amount of $287,900 and commenced receiving his Retirement Plan — Special Annuity Credit benefit in the
amount of $10,842 monthly on November 1, 2016. His MSBP benefit of $290,468 monthly became due beginning
on November 1, 2016. Payment of the first six months are delayed until May 2, 2017 pursuant to Code Section 409A.

Mr. Hayes was not entitled to any severance benefits or payments in connection with his resignation. The
only payment Mr. Hayes will receive is a lump distribution of his ESRP benefit on June 1, 2017, as a result of the
six month delay required under Code Section 409A and at this time has made no election to commence his Retirement
Plan — Cash Balance Component benefit.

Director Compensation

The following table provides information concerning the compensation of each person, other than Mr. Welch, who
served as a director of the Company during 2016. Mr. Welch’s compensation is set forth in the “Summary
Compensation Table”.

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Director Compensation Table

Name (1)

(a)

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

Stock Awards ($) (3)

Total ($)

(b)

(c)

(h)

Albert Ernst

Rhys D. Evenden

Christopher H. Franklin

Edward G. Jepsen

James P. Laurito

David R. Lopez

Hazel R. O’Leary

Barry V. Perry

Thomas G. Stephens

G. Bennett Stewart

Lee C. Stewart

67,292

63,669

26,835

75,209

26,835

75,209

26,835

67,292

87,084

—

63,669

—

63,669

—

63,669

130,961

26,835

138,878

26,835

138,878

26,835

130,961

150,753

____________________________

(1) Messrs. Evenden, Laurito and Perry were appointed to the Board on October 14, 2016. Ms. O’Leary
and Messrs. Ernst, Franklin, Lopez, Stephens, G. Bennett Stewart and Lee Stewart left the Board on
October 14, 2016 with the closing of the Merger. Messrs. Ernst and Stephens were reappointed to the
Board, effective January 1, 2017.

(2) Includes annual Board retainer and committee chairmanship retainer, as well as a lead director fee (for

Mr. Lee Stewart only).

(3) Aggregate grant date fair value is computed in accordance with ASC 718. Awards of restricted stock
are made quarterly prior to the Merger and recorded at fair value at the date of grant. The values for
Ms. O’Leary and Messrs. Ernst, Franklin, Jepsen, Lopez, Stephens, Bennett Stewart and Lee Stewart
awards were $63,669 (equivalent to 487 shares at $43.57 per share, 453 shares at $46.82 per share
and 457 shares at $46.48 per share). There were no outstanding stock awards as of December 31,
2016.

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

The table below reflects the amounts paid in cash to non-employee directors serving as such at the time of the
Merger for unvested restricted stock awards that were vested and paid in accordance with the Merger Agreement
in the same manner as described in “Compensation Discussion and Analysis — Merger Agreement and the Merger.”

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Name
(a)

Albert Ernst

Christopher H. Franklin

Edward G. Jepsen

David R. Lopez

Hazel R. O’Leary

Thomas G. Stephens

G. Bennett Stewart

Lee C. Stewart

Stock Awards

Number of
Shares (#)
(d)

Value
Realized ($)
(e)

4,528 $

5,806

4,528

5,806

5,806 $

207,020

265,450

207,020

265,450

Under the non-employee director compensation policy prior to the Merger, all non-employee directors were
paid an annual cash retainer of $85,000 and an annual equity retainer of restricted stock with a total value of $85,000
(awarded through quarterly grants valued at $21,250 each). In addition, we paid an additional cash retainer of
$10,000 annually to the chair of each Board committee and $25,000 annually to our lead director. We did not pay
per-meeting fees under the policy. Directors had the discretion to make individual elections to receive anywhere
from 50% to 100% of the total annual cash retainer in grants of Company stock with the same vesting provisions as
described for restricted stock grants below. Directors were reimbursed for their out-of-pocket expenses in an
accountable expense plan.

Under the director compensation policy that applies currently, all non-employee directors 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.

Compensation Committee Interlocks and Insider Participation

During 2016 prior to the closing of the Merger, the Committee consisted of Mr. Stephens as well as David
Lopez and Hazel O’Leary, each of whom was an independent director and had no current or former employment
relationship with the Company. The Board of Directors was reconstituted as a result of the Merger on October 14,
2016, to consist of Messrs. Welch (our President and Chief Executive Officer through November 1, 2016), Perry,
Laurito and Evenden, each of whom also served as a member of the Governance and Human Resources Committee
from that date until independent directors were elected and the Board’s committees were reconstituted in January
2017.

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, 2017, 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, 2017 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:

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Name of Beneficial Owner

Joseph L. Welch
Linda H. Blair
Gretchen L. Holloway
Jon E. Jipping
Daniel J. Oginsky
Christine Mason Soneral
Rejji P. Hayes
Albert Ernst
Rhys D. Evenden
Robert A. Elliott
James P. Laurito
Barry V. Perry
Sandra E. Pierce
Kevin L. Prust
Thomas G. Stephens
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

—
—
—
—
—
—
—
—
—
—
—
—
—
—
—

—

—% 1,178,328 (1)
53,889
—%
3,159
—%
120,000
—%
72,631
—%
—
—%
—%
1,755
—% 14,022 (2)
—
—%
—
—%
—%
—
—% 205,234 (3)
—
—%
—
—%
2,098
—%

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

—%

1,651,106

* 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)

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

(3)

Includes 28,715 shares owned by the spouse and children of Mr. Perry.

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

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

At December 31, 2016, there were no securities authorized for issuance under any compensation plans

of ITC Holdings.

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

CERTAIN TRANSACTIONS

Pursuant to its charter, the Governance and Human Resources Committee is charged with monitoring and
reviewing issues involving independence and potential conflicts of interest with respect to our directors and
executive officers. The Governance and Human Resources Committee also determines whether or not a particular
relationship serves the best interest of the Company and its shareholders 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

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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 and former chief executive officer) were employed by us as
a Senior Engineer, Fleet Manager, Manager of Corporate and Field Facilities, and Senior Accountant, respectively,
during 2016 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 $795,369 during 2016.

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. Ernst, Elliott, Prust and Stephens are “independent”
as defined in as 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, the Company’s 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
(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.

Mr. Ernst was a member of the law firm Dykema Gossett PLLC until he retired in August 2014. We made
payments for legal services to the Dykema law firm amounting to less than 5% of its gross revenues during each
of the last three calendar years. However, as a former member of Dykema who has no consulting or employment
relationship with that firm, Mr. Ernst has no financial or other interest in payments made to that firm following his
retirement. Our Board considered this former relationship when determining that Mr. Ernst is independent and
determined that this relationship was not material and was unlikely to affect his ability to act as an independent
board member.

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ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.

The following table provides a summary of the aggregate fees incurred for Deloitte’s services in 2016 and 2015:

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

____________________________

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

2015
1,855,636
113,239
209,689
5,000
2,183,564

(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 and attendance at the Deloitte Power and Utilities
Seminar.

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, or the Audit and Finance Committee with respect to actions prior to the

Merger, approved all of the services performed by Deloitte in 2016.

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Table of Contents

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, 2016 and 2015

Consolidated Statements of Operations for the Years Ended December 31, 2016, 2015 and 2014

Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2016, 2015 and 2014

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

2014

Consolidated Statements of Cash Flows for the Years Ended December 31, 2016, 2015 and 2014

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)

The exhibits included as part of this report are listed in the attached Exhibit Index, which is incorporated herein by
reference.

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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 STOCKHOLDERS’ 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 $16 and $14,

respectively)

STOCKHOLDERS’ EQUITY

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

2016, and 224,203,112 and 152,699,077 shares issued and outstanding at
December 31, 2016 and 2015, respectively

Retained earnings
Accumulated other comprehensive income

Total stockholders’ equity

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY

December 31,

2016

2015

4
16
17
8
45

4,171
208
78
4,457
4,502

85
14
33
195
13
340
68
1

8
38
—
2
48

4,011
21
65
4,097
4,145

—
24
35
395
10
464
62
1

2,192

1,909

892
1,007
2
1,901
4,502

829
876
4
1,709
4,145

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

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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
Interest expense
Loss on extinguishment of debt
Other expense
LOSS BEFORE INCOME TAXES
INCOME TAX BENEFIT
LOSS AFTER TAXES
EQUITY IN SUBSIDIARIES’ NET EARNINGS
NET INCOME

Year Ended December 31,
2015

2014

2016

1 $

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

1 $
(6)
(106)
—
—
(111)
(45)
(66)
308
242 $

1
(7)
(105)
(29)
(1)
(141)
(55)
(86)
330
244

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

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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,
2015

2014

2016

246 $

242 $

244

Derivative instruments (net of tax of $3, $1 and $2 for the years ended

December 31, 2016, 2015 and 2014, respectively)
TOTAL OTHER COMPREHENSIVE LOSS, NET OF TAX
TOTAL COMPREHENSIVE INCOME

(2)
(2)
244 $

(1)
(1)
241 $

(2)
(2)
242

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

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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

Year Ended December 31,
2015

2014

2016

Net income
Adjustments to reconcile net income to net cash (used in) provided by operating activities:

246

242

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
Loss on extinguishment of debt
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
Tax benefit on the excess tax deduction of share-based compensation
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

Net cash (used in) provided by financing activities

NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS

CASH AND CASH EQUIVALENTS — Beginning of period

CASH AND CASH EQUIVALENTS — End of period

(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)

(308)
185
(116)
121
—
—
21

3
—
—
—
1
9
(12)
3
7
156

(263)
161
(11)
(113)

—
839
—
95
—
(755)
—
(108)
—
14
(137)

—

12
—
—
(1)
(41)
2

6
8

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

244

(330)
224
(122)
124
—
29
18

1
—
4
—
2
11
(8)
(9)
4
192

(349)
127
(7)
(229)

399
534
60
—
(249)
(480)
(39)
(96)
—
21
(134)

—

8
(20)
20
(8)
16
(21)
27
6

141

Table of Contents

SCHEDULE I — Condensed Financial Information of Registrant

ITC HOLDINGS CORP.

NOTES TO CONDENSED FINANCIAL STATEMENTS (PARENT COMPANY ONLY)

1. GENERAL

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

As a holding company with no business operations, ITC Holdings’ assets consist primarily of investments in
our subsidiaries. ITC Holdings’ material cash inflows are only from dividends and other payments received from
our subsidiaries, the proceeds raised from the sale of debt securities, issuances under our commercial paper
program and borrowings under our revolving credit agreement. ITC Holdings may not be able to access cash
generated by our subsidiaries in order to fulfill cash commitments. The ability of our subsidiaries to make dividend
and other payments to us is subject to the availability of funds after taking into account their respective funding
requirements, the terms of their respective indebtedness, the regulations of the FERC under the FPA and applicable
state laws. In addition, there are practical limitations on using the net assets of each of our Regulated Operating
Subsidiaries as of December 31, 2016 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 (net of interest capitalized)
Income taxes paid (a)

Supplementary non-cash investing and financing activities:

Equity transfers to subsidiaries
____________________________

Year Ended December 31,
2015

2014

2016

112 $

104 $

—

106
45

(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, 2016, the maturities of our debt outstanding were as follows:

(In millions)
2017
2018
2019
2020
2021
2022 and thereafter

Total

195
385
73
200
—
1,550
2,403

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
$2,297 million and $2,059 million at December 31, 2016 and 2015, respectively. The total book value of the ITC

142

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Holdings Senior Notes, net of discount and deferred financing fees, was $2,169 million and $1,921 million at
December 31, 2016 and 2015, respectively. At December 31, 2016 and 2015, we had a total of $73 million and
$299 million, respectively, outstanding under our revolving and term loan credit agreements, which are variable
rate loans. The fair value of these loans approximates book value based on the borrowing rates currently available
for variable rate loans obtained from third party lending institutions. These fair values represent Level 2 under the
three-tier hierarchy described in Note 12 to the consolidated financial statements. At December 31, 2016 and 2015,
ITC Holdings had $145 million and $95 million, respectively, of commercial paper issued and outstanding under
the commercial paper program. Due to the short-term nature of these financial instruments, the carrying value
approximates fair value.

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 and paying
dividends. In addition, the covenants require us to meet certain financial ratios, such as maintaining certain debt
to capitalization ratios. At December 31, 2016, we were not in violation of any debt covenant.

3. RELATED-PARTY TRANSACTIONS

Our related-party transactions during 2016, 2015 and 2014 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

MTH

ITC Midwest

ITC Great Plains

2016

Year Ended December 31,
2015

87 $

263 $

2014

274

185

161

(28) $

36 $

(14)

(34)

349

224

127

____________________________

(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.

143

Table of Contents

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 16, 2017.

SIGNATURES

ITC HOLDINGS CORP.

By: /s/ LINDA H. BLAIR
Linda H. Blair

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. BLAIR
Linda H. Blair

President and Chief
Executive Officer (principal executive officer)

/s/ GRETCHEN L. HOLLOWAY
Gretchen L. Holloway

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

Date

February 16, 2017

/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/ THOMAS G. STEPHENS
Thomas G. Stephens

Director and Chairman

February 16, 2017

Director

February 16, 2017

Director

February 16, 2017

Director

February 16, 2017

Director

February 16, 2017

Director

February 16, 2017

Director

February 16, 2017

Director

February 16, 2017

Director

February 16, 2017

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Table of Contents

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.

EXHIBITS

Exhibit No.

Description of Exhibit

2.1

3.1

3.2

4.3

4.5

4.6

4.7

4.8

4.9

4.10

4.12

4.14

4.17

4.18

4.19

4.20

4.21

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 filed 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 filed on
October 12, 2016)

Indenture, dated as of July 16, 2003, between the Registrant 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 filed on March 30, 2006)

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 filed 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 filed 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 filed 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 Form8-K filed 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 filed 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 filed on March 27, 2008)

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Table of Contents

Exhibit No.

Description of Exhibit

4.23

4.24

4.25

4.26

4.27

4.28

4.29

4.30

4.31

4.32

4.33

4.34

4.35

4.36

4.38

4.39

4.40

4.41

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 filed 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 filed 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 filed 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 filed 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 filed 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 filed 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 filed 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 filed on April 8, 2013)

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

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

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

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)

146

Table of Contents

Exhibit No.

Description of Exhibit

4.42

4.43

4.44

4.45

*10.27

*10.45

*10.46

10.51

*10.64

*10.75

*10.76

*10.77

*10.78

*10.80

*10.81

*10.97

10.104

10.105

*10.108

*10.109

*10.110

*10.111

*10.112

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 filed 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 filed on April 26, 2016)

Third Supplemental Indenture, dated as of July 5, 2016, between the Company and Wells Fargo Bank,
National Association, as trustee, together with form of 3.25% Note due 2026 (filed with Registrant’s Form
8-K filed on July 5, 2016)

Deferred Compensation Plan (filed with Registrant’s Registration Statement on Form S-1, as amended,
Reg. No. 333-123657)

Form of Restricted Stock Award Agreement for Employees under the Registrant’s 2006 Long Term Incentive
Plan (filed with Registrant’s Form 8-K filed on August 18, 2006)

Form of Stock Option Agreement for Employees under the Registrant’s 2006 Long Term Incentive Plan
(filed with Registrant’s Form 8-K filed on August 18, 2006)

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)

Form of Amended and Restated Executive Group Special Bonus Plan of the Registrant, dated November
12, 2007 (filed with Registrant’s 2007 Form 10-K)

Form of Amendment to Stock Option Agreement under 2006 LTIP (August 2008) (filed with Registrant’s
Form 8-K filed on August 19, 2008)

Form of Amendment to Restricted Stock Agreement under 2006 LTIP) (August 2008) (filed with Registrant’s
Form 8-K filed on August 19, 2008)

Form of Stock Option Agreement under 2006 LTIP (August 2008) (filed with Registrant’s Form 8-K filed
on August 19, 2008)

Form of Restricted Stock Award Agreement under 2006 LTIP (August 2008) (filed with Registrant’s Form
8-K filed on August 19, 2008)

Management Supplemental Benefit Plan (filed with Registrant’s 2008 Form 10-K)

Executive Supplemental Retirement Plan (filed with Registrant’s 2008 Form 10-K)

Second Amended and Restated 2006 Long Term Incentive Plan effective May 26, 2011 (filed with
Registrant’s Form 8-K on June 1, 2011)

Form of Stock Option Agreement for Executive Officers under Second Amended and Restated 2006 LTIP
(May 2012) (filed with Registrant’s Form 10-Q for the quarter ended June 30, 2012)

Form of Restricted Stock Award Agreement for Executive Officers under Second Amended and Restated
2006 LTIP (May 2012) (filed with Registrant’s Form 10-Q for the quarter ended June 30, 2012)

Employment Agreement between ITC Holdings Corp. and Joseph L. Welch, effective as of December 21,
2012 (filed with Registrant's Form 8-K on December 26, 2012)

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)

Retention Compensation Agreement between ITC Holdings Corp. and Joseph L. Welch, dated as of
December 21, 2012 (filed with Registrant's Form 8-K on December 26, 2012)

147

Table of Contents

Exhibit No.

*10.120

*10.122

10.126

10.127

10.128

10.129

10.130

*10.133

*10.134

*10.135

*10.136

*10.138

*10.141

*10.143

*10.144

*10.145

*10.146

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)

Form of Notice and Amendment to Stock Option Agreement for Executive Officers under Amended and
Restated 2003 Stock Purchase and Option Plan, as amended (May 2014) (filed with Registrant’s Form
10-Q for quarter ended June 30, 2014)

Form of Notice and Amendment to Stock Option Agreement for Executive Officers under Second Amended
and Restated 2006 LTIP (May 2014) (filed with Registrant’s Form 10-Q for quarter ended June 30, 2014)

Form of Stock Option Agreement for Executive Officers under Second Amended and Restated 2006 LTIP
(May 2014) (filed with Registrant’s Form 10-Q for quarter ended June 30, 2014)

Form of Stock Award Agreement for Executive Officers under Second Amended and Restated 2006 LTIP
(May 2014) (filed with Registrant’s Form 10-Q for quarter ended June 30, 2014)

Employment Agreement between ITC Holdings Corp. and Rejji P. Hayes, effective as of October 27, 2014
(filed with Registrant’s Form 8-K on October 29, 2014)

Form of Restricted Stock Award Agreement (5 year vesting) (February 2015) (filed with Registrant’s Form
10-Q for the quarter ended March 30, 2015)

ITC Holdings Corp. 2015 Employee Stock Purchase Plan (filed with Registrant’s Form 10-Q for the quarter
ended June 30, 2015)

ITC Holdings Corp. 2015 Long Term Incentive Plan (filed with Registrant’s Form 10-Q for the quarter ended
June 30, 2015)

Form of Stock Option Grant Agreement under Second Amended and Restated 2006 LTIP (May 2015)
(filed with Registrant’s Form 10-Q for the quarter ended June 30, 2015)

Form of Restricted Stock Grant Agreement under Second Amended and Restated 2006 LTIP (May 2015)
(filed with Registrant’s Form 10-Q for the quarter ended June 30, 2015)

148

Table of Contents

Exhibit No.

Description of Exhibit

*10.147

*10.148

*10.149

*10.150

10.152

*10.155

*10.156

10.157

10.158

10.159

10.160

10.161

*10.162

*10.163

*10.164

*10.165

*10.166

Form of Performance Share Award Agreement under Second Amended and Restated 2006 LTIP (May
2015) (filed with Registrant’s Form 10-Q for the quarter ended June 30, 2015)

Form of Amendment to 2014 Stock Option Grant Agreement (May 2015) (filed with Registrant’s Form 10-
Q for the quarter ended June 30, 2015)

Form of Amendment to 2014 Restricted Stock Grant Agreement (May 2015) (filed with Registrant’s Form
10-Q for the quarter ended June 30, 2015)

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)

METC 2015 Term Loan Credit Agreement dated as of December 8, 2015, among Michigan Electric
Transmission Company, LLC, the various financial institutions and other persons from time to time parties
thereto as lenders, and Barclays Bank PLC, as administrative agent for the Lenders and the other agents
party thereto. (filed with Registrant’s Form 8-K on December 10, 2015)

Letter Agreement, dated as of February 8, 2016, between ITC Holdings Corp. and Joseph L. Welch (filed
with Registrant’s Form 8-K filed on February 11, 2016)

Summary of 2016 Incentive Compensation Plan (filed with Registrant’s Form 10-Q for the quarter ended
March 31, 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 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 filed 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 filed 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 filed 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 filed 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 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 filed on April 11, 2016)

Form of Restricted Stock Award Agreement for Executive Officers under 2015 Long Term Incentive Plan
(May 2016) (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 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 Rejji P. Hayes (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)

149

Table of Contents

Exhibit No.

Description of Exhibit

*10.167

*10.168

*10.169

*10.171

*10.172

*10.173

*10.174

*10.175

12.1

31.1

31.2

Letter Agreement, dated as of October 14, 2016, between ITC Holdings Corp. and Joseph L. Welch (filed
with Registrant’s Form 8-K filed on October 12, 2016)

Letter Agreement, dated as of October 14, 2016, between ITC Holdings Corp. and Linda H. Blair (filed
with Registrant’s Form 8-K filed on October 12, 2016)

Amended Employment Agreement, dated as of October 12, 2016, between ITC Holdings Corp. and Rejji
P. Hayes (filed with Registrant’s Form 8-K filed on October 12, 2016)

Amendment to Management Supplemental Benefit Plan, effective as of October 14, 2016

Employment Agreement between ITC Holdings Corp. and Gretchen L. Holloway, effective as of February
3, 2015.

Amended Employment Agreement, dated as of October 12, 2016 between ITC Holdings Corp. and
Christine Mason Soneral

Retention Award Letter, dated May 19, 2016 between ITC Holdings Corp. and Christine Mason Soneral

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

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.

150