ITC Itc Holdings Corp.

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.)

Large accelerated filer o		Accelerated filer o		Non-accelerated filer   þ		Smaller Reporting Company o		Emerging growth company   o

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

•	“ITC Holdings” are references to ITC Holdings Corp. and not any of its subsidiaries;

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

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

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

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

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

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

•	“Regulated Operating Subsidiaries” are references to ITCTransmission, METC, ITC Midwest, ITC Great Plains and ITC Interconnection together; and

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

•	“2017 Omnibus Plan” are references to the Company’s February 27, 2017 long-term equity incentive plan as amended July 10, 2017;

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

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

•	“AFUDC” are references to an allowance for funds used during construction;

•	“ALJ” are references to an administrative law judge;

•	“Ancillary Services Agreement” are references to the Amended and Restated Purchase and Sale Agreement for Ancillary Services entered into by METC and Consumers Energy dated as of April 29, 2002;

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

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

•	“CIA” are references to the Coordination and Interconnection Agreement entered into by ITCTransmission and DTE Electric dated as of February 28, 2003;

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

•	“D.C. Circuit Court” are references to the U.S. Court of Appeals for the District of Columbia Circuit;

•	“DCF” are references to discounted cash flow;

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

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

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

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

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

•	“Easement Agreement” are references to the Amended and Restated Easement Agreement entered into by METC and Consumers Energy dated April 29, 2002 and as further supplemented;

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

•	“ESPP” are references to the Fortis Amended and Restated 2012 Employee Share Purchase Plan;

•	“Exchange Act” are references to the Securities Exchange Act of 1934, as amended;

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

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

•	“Fortis” are references to Fortis Inc.;

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

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

•	“FPA” are references to the Federal Power Act;

•	“GAAP” are references to accounting principles generally accepted in the United States of America;

•	“Generator Interconnection Agreement” are references to the Amended and Restated Generator Interconnection Agreement entered into by Consumers Energy and METC dated as of April 29, 2002 and most recently amended effective as of November 1, 2018;

•	“GIC” are references to GIC Private Limited;

•	“GIAs” are references to generator interconnection agreements;

•	“GIOA” are references to the Generator Interconnection and Operation Agreement entered into by DTE Electric and ITCTransmission dated as of February 28, 2003;

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

•	“Investment Holdings” are references to ITC Investment Holdings Inc., a majority owned indirect subsidiary of Fortis in which GIC has an indirect minority ownership interest;

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

•	“IRS” are references to the Internal Revenue Service;

•	“ISO” are references to Independent System Operators;

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

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

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

•	“LBA” are references to a Local Balancing Authority;

•	“LGIA” are references to the Large Generator Interconnection Agreement entered into by ITC Midwest, IP&L, and MISO dated as of December 20, 2007 and amended as of August 2, 2017;

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

•	“Merger” are references to the merger with Fortis, whereby ITC Holdings merged with Merger Sub and subsequently became a majority owned indirect subsidiary of Fortis;

•	“Merger Agreement” are references to the agreement and plan of merger between Fortis, FortisUS, Merger Sub and ITC Holdings for the Merger;

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•	“Merger Sub” are references to Element Acquisition Sub, Inc., an indirect subsidiary of Fortis that merged into ITC Holdings in the Merger;

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

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

•	“MISO” are references to the Midcontinent Independent System Operator, Inc., a FERC-approved RTO which oversees the operation of the bulk power transmission system for a substantial portion of the Midwestern United States and Manitoba, Canada, and of which ITCTransmission, METC and ITC Midwest are members;

•	“MOA” are references to the Master Operating Agreement entered into by ITCTransmission and DTE Electric dated as of February 28, 2003;

•	“Moody’s” are references Moody’s Investor Service, Inc.;

•	“MVPs” are references to multi-value projects, which have been determined by MISO to have regional value while meeting near-term system needs;

•	“MW” are references to megawatts (one megawatt equaling 1,000,000 watts);

•	“NERC” are references to the North American Electric Reliability Corporation;

•	“NOLs” are references to net operating loss carryforwards for income taxes;

•	“November 2018 Order” are references to an order issued by the FERC on November 15, 2018 regarding MISO base ROE complaints;

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

•	“Operating Agreement” are references to the Amended and Restated Operating Agreement entered into by Consumers Energy and METC dated as of April 29, 2002;

•	“OSA” are references to the Operations Services Agreement for 34.5 kV Transmission Facilities entered into by ITC Midwest and IP&L effective as of January 1, 2011;

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

•	“PCBs” are references to polychlorinated biphenyls;

•	“ROE” are references to return on equity;

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

•	“RTO” are references to Regional Transmission Organizations;

•	“SBU” are references to a service-based unit;

•	“SEC” are references to the Securities and Exchange Commission;

•	“Second Complaint” are references to an additional complaint filed on February 12, 2015 with the FERC under Section 206 of the FPA regarding ROE;

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

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

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

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

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•	“TCJA” are references to the Tax Cuts and Jobs Act of 2017, a comprehensive tax reform bill enacted on December 22, 2017;

•	“TO” are references to transmission owners; and

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

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PART I

ITEM 1.     BUSINESS.

Overview

Our business consists primarily of the electric transmission operations of our Regulated Operating Subsidiaries. ITC Holdings was incorporated in the State of Michigan in 2002. Through our Regulated Operating Subsidiaries, we own and operate high-voltage systems in Michigan’s Lower Peninsula and portions of Iowa, Minnesota, Illinois, Missouri, Kansas and Oklahoma that transmit electricity from generating stations to local distribution facilities connected to our systems. Our business strategy is to own, operate, maintain and invest in transmission infrastructure in order to enhance system integrity and reliability, reduce transmission constraints and support new generating resources to interconnect to our transmission systems. We also are pursuing development projects outside our existing systems.

As electric transmission utilities with rates regulated by the FERC, our Regulated Operating Subsidiaries earn revenues for the use of their electric transmission systems by our customers, which include investor-owned utilities, municipalities, cooperatives, power marketers and alternative energy suppliers. As independent transmission companies, our Regulated Operating Subsidiaries are subject to rate regulation only by the FERC, and our cost-based rates are discussed in “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cost-Based Formula Rates with True-Up Mechanism.”

The Merger

On February 9, 2016, ITC Holdings entered into the Merger Agreement with Fortis, FortisUS and Merger Sub. On April 20, 2016, Fortis reached a definitive agreement with GIC for GIC to acquire an indirect 19.9% equity interest in ITC Holdings upon completion of the Merger. On October 14, 2016 , ITC Holdings and Fortis completed the Merger contemplated by the Merger Agreement. On the same date, the common shares of ITC Holdings were delisted from the NYSE. Due to the delisting of ITC Holdings common shares, there is limited share data, and no per share data, presented in this Form 10-K. Refer to Note 1 to the consolidated financial statements for further details on the Merger.

Development of Business

We are actively identifying and investing in transmission infrastructure required to meet reliability needs and energy policy objectives. Our long-term growth plan includes ongoing investments in our current regulated transmission systems and the identification of incremental development projects throughout North America. Refer to “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Investment and Operating Results Trends” for additional details about our long-term capital investments. Refer to the discussion of risks associated with our strategic development opportunities in “Item 1A Risk Factors.”

We expect to invest approximately $3.5 billion from 2019 through 2023 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; (3) upgrade physical and technological grid security and (4) develop and build regional transmission infrastructure, including additional transmission facilities that will provide interconnection opportunities for generating facilities.

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

Operations

As transmission-only companies, our Regulated Operating Subsidiaries function as conduits, allowing for power from generators to be transmitted to local distribution systems either entirely through 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;

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•	engineering, design and construction;

•	asset protection and performance

•	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.

Asset Protection and Performance

The Asset Protection and Performance group is responsible for safety, human performance, security, and emergency preparedness and response. Given the inherent hazardous nature of the utilities industry, we proactively work to ensure that all personnel are free to perform in a safe and secure environment. Our focus is not to compromise the safety of our employees, contractors or the public in the course of providing the most reliable electricity transmission services.

Due to the growing trend in the theft of data, the security of hard assets including laptops, mechanical keys, badges, etc. is critical. We have established guidelines to help maintain the security of company assets and regularly monitor potential security threats. Separate from the Asset Protection and Performance group, we have a Cyber Security group that develops, refines and monitors a comprehensive and complex cyber security system to protect our infrastructure.

Maintenance

We develop and track preventive maintenance plans to promote safe and reliable systems. By performing preventive maintenance on our assets, we can minimize the need for reactive maintenance, resulting in improved reliability. Our Regulated Operating Subsidiaries contract with ULCS, which is a division of Asplundh Tree Expert Co., to perform the majority of their maintenance. The agreement with ULCS provides us with access to an experienced and scalable workforce with knowledge of our system at an established rate.

Real Time Operations

System Operations — From our operations facility in Novi, Michigan, transmission system operators continuously monitor the performance of the transmission systems of our Regulated Operating Subsidiaries, using software and communication systems to perform analysis to plan for contingencies and maintain security and reliability following any unplanned events on the system. Transmission system operators are also responsible for the switching and protective tagging function, taking equipment in and out of service to ensure capital construction projects and maintenance programs can be completed safely and reliably.

Local Balancing Authority Operator — Under the functional control of MISO, ITCTransmission and METC operate their electric transmission systems as a combined LBA area, known as MECS. From our operations facility in Novi, Michigan, our employees perform the LBA functions as outlined in MISO’s Balancing Authority Agreement. These functions include actual interchange data administration and verification as well as MECS LBA area emergency procedure implementation and coordination. Besides ITCTransmission and METC, our other Regulated Operating Subsidiaries are not responsible for LBA functions for their respective assets.

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Operating Contracts

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

ITCTransmission

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

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

Generator Interconnection and Operation Agreement. The GIOA established, re-established and maintains the direct electricity interconnection of DTE Electric’s electricity generating assets with ITCTransmission’s transmission system for the purposes of transmitting electric power from and to the electricity generating facilities.

Coordination and Interconnection Agreement. The CIA governs the rights, obligations and responsibilities of ITCTransmission and DTE Electric regarding, among other things, the operation and interconnection of DTE Electric’s distribution system and ITCTransmission’s transmission system, and the construction of new facilities or modification of existing facilities. Additionally, the CIA allocates costs for operation of supervisory, communications and metering equipment.

METC

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

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

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

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

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

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

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ITC Midwest

IP&L operates the electric distribution system to which ITC Midwest’s transmission system connects. ITC Midwest is a party to a number of operating contracts with IP&L that govern the operations and maintenance of its transmission system. These contracts include the following:

Distribution-Transmission Interconnection Agreement. The DTIA governs the rights, responsibilities and obligations of ITC Midwest and IP&L, with respect to the use of certain of their own and the other parties’ property, assets and facilities and the construction of new facilities or modification of existing facilities.

Large Generator Interconnection Agreement. ITC Midwest, IP&L and MISO entered into the LGIA in order to establish, re-establish and maintain the direct electricity interconnection of IP&L’s electricity generating assets with ITC Midwest’s transmission system for the purposes of transmitting electric power from and to the electricity generating facilities.

Operations Services Agreement For 34.5 kV Transmission Facilities. ITC Midwest and IP&L entered into the OSA under which IP&L performs certain operations functions for ITC Midwest’s 34.5 kV transmission system on behalf of ITC Midwest. The OSA provides that when ITC Midwest upgrades 34.5 kV facilities to higher operating voltages it may notify IP&L of the change and the OSA is no longer applicable to those facilities.

ITC Great Plains

Amended and Restated Maintenance Agreement. Mid-Kansas and ITC Great Plains have entered into the Mid-Kansas Agreement pursuant to which Mid-Kansas has agreed to perform various field operations and maintenance services related to certain ITC Great Plains assets.

ITC Interconnection

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

Regulatory Environment

Many regulators and public policy makers support the need for further investment in the transmission grid. The growth and changing mix of electricity generation, wholesale power sales and consumption combined with historically inadequate transmission investment have resulted in significant transmission constraints across the United States and increased stress on aging equipment. These problems will continue without increased investment in transmission infrastructure. Transmission system investments can also increase system reliability and reduce the frequency of power outages. Such investments can reduce transmission constraints and improve access to lower cost generation resources, resulting in a lower overall cost of delivered electricity for end-use consumers. The DOE has established the Office of Electricity that focuses on working with reliability experts from the power industry, state governments and their Canadian counterparts to improve grid reliability and increase investment in the country’s electric infrastructure. In addition, the FERC has signaled its desire for substantial new investment in the transmission sector by implementing various financial and other incentives.

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

The FERC requires compliance with certain reliability standards by TOs and may take enforcement actions for violations, including the imposition of substantial fines. NERC is responsible for developing and enforcing these mandatory reliability standards. We continually assess our transmission systems against standards established

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by NERC, as well as the standards of applicable regional entities under NERC that have been delegated certain authority for the purpose of proposing and enforcing reliability standards. Finally, utility holding companies are subject to FERC regulations related to access to books and records in addition to the requirement of the FERC to review and approve mergers and consolidations involving utility assets and holding companies in certain circumstances.

Federal Regulation

As electric transmission companies, our Regulated Operating Subsidiaries charge rates that are regulated by the FERC. The FERC is an independent regulatory commission within the DOE that regulates the interstate transmission and certain wholesale sales of natural gas, the transmission of oil and oil products by pipeline and the transmission and wholesale sales of electricity in interstate commerce. The FERC also administers accounting and financial reporting regulations and standards of conduct for the companies it regulates. In 1996, in order to facilitate open access transmission for participants in wholesale power markets, the FERC issued Order No. 888. Order No. 888 encouraged investor owned utilities to cede operational control over their transmission systems to ISOs, which are not-for-profit entities.

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

In 2011, the FERC issued Order No. 1000, which amends certain existing transmission planning and cost allocation requirements to ensure that FERC-jurisdictional services are provided at just and reasonable rates and on a basis that is just and reasonable and not unduly discriminatory or preferential. Order No. 1000 can create competition for certain future transmission projects, including within our current operating areas. As a part of our identification of incremental development opportunities as it relates to our plans, we are exploring opportunities resulting from Order No. 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 have experienced long-term growth as a result of projects that have been identified as having regional benefits and are therefore eligible for regional cost recovery. Separate calculations of revenue requirement are performed for projects that have been approved for regional cost sharing.

We have projects that are eligible for regional cost sharing under the MISO tariff, such as certain network upgrade projects, and the MVPs, including our portions of the four MVPs and the Thumb Loop Project in Michigan. Additionally, certain projects at ITC Great Plains are eligible for recovery through a region-wide charge in the SPP tariff, including three regional cost sharing projects in Kansas.

State Regulation

The regulatory agencies in the states where our Regulated Operating Subsidiaries’ assets are located do not have jurisdiction over our rates or terms and conditions of service. However, they typically have jurisdiction over siting of transmission facilities and related matters as described below. Additionally, we are subject to the regulatory oversight of various state environmental quality departments for compliance with any state environmental standards and regulations.

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ITCTransmission, METC and ITC Interconnection

Michigan

The Michigan Public Service Commission has jurisdiction over the siting of certain transmission facilities. Additionally, ITCTransmission, METC and ITC Interconnection have the right as independent transmission companies to condemn property in the state of Michigan for the purposes of building or maintaining transmission facilities.

ITCTransmission, METC and ITC Interconnection are also subject to the regulatory oversight of the Michigan Department of Environmental Quality, the Michigan Department of Natural Resources and certain local authorities for compliance with all environmental standards and regulations.

ITC Midwest

Iowa

The Iowa Utilities Board has the power of supervision over the construction, operation and maintenance of transmission facilities in Iowa by any entity, which includes the power to issue franchises. Iowa law further provides that any entity granted a franchise by the Iowa Utilities Board is vested with the power of condemnation in Iowa to the extent the Iowa Utilities Board approves and deems necessary for public use. A city has the power, pursuant to Iowa law, to grant a franchise to erect, maintain and operate transmission facilities within the city, which franchise may regulate the conditions required and manner of use of the streets and public grounds of the city and may confer the power to appropriate and condemn private property.

ITC Midwest also is subject to the regulatory oversight of certain state agencies (including the Iowa Department of Natural Resources) and certain local authorities with respect to the issuance of environmental, highway, railroad and similar permits.

Minnesota

The Minnesota Public Utilities Commission has jurisdiction over the construction, siting and routing of new transmission lines or upgrades of existing lines through Minnesota’s Certificate of Need and Route Permit Processes. Transmission companies are also required to participate in the State’s Biennial Transmission Planning Process and are subject to the state’s preventative maintenance requirements. Pursuant to Minnesota law, ITC Midwest has the right as an independent transmission company to condemn property in the state of Minnesota for the purpose of building new transmission facilities.

ITC Midwest is also subject to the regulatory oversight of the Minnesota Pollution Control Agency, the Minnesota Department of Natural Resources, the Minnesota Public Utilities Commission in conjunction with the Department of Commerce and certain local authorities for compliance with applicable environmental standards and regulations.

Illinois

The Illinois Commerce Commission exercises jurisdiction over siting of new transmission lines through its requirements for Certificates of Public Convenience and Necessity and Right-Of-Way acquisition that apply to construction of new or upgraded facilities.

ITC Midwest is also subject to the regulatory oversight of the Illinois Environmental Protection Agency, the Illinois Department of Natural Resources, the Illinois Pollution Control Board and certain local authorities for compliance with all environmental standards and regulations.

Missouri

Because ITC Midwest is a “public utility” and an “electrical corporation” under Missouri law, the Missouri Public Service Commission has jurisdiction to determine whether ITC Midwest may operate in such capacity. The Missouri Public Service Commission also exercises jurisdiction with regard to other non-rate matters affecting this Missouri asset such as transmission substation construction, general safety and the transfer of the franchise or property.

ITC Midwest is also subject to the regulatory oversight of the Missouri Department of Natural Resources for compliance with all environmental standards and regulations relating to this transmission line.

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Wisconsin

ITC Midwest is a “public utility” and independent transmission owner in Wisconsin. The Public Service Commission of Wisconsin granted ITC Midwest a certificate of authority to transact public utility business in the state. The Public Service Commission of Wisconsin also recognized ITC Holdings as a public utility holding company under Wisconsin statutes.

The Public Service Commission of Wisconsin exercises jurisdiction over the siting of new transmission lines through the issuance of certificates of authority and certificates of public convenience and necessity. Upon receipt of such certificates for a transmission project, ITC Midwest has condemnation authority as a foreign transmission provider under Wisconsin law. ITC Midwest is also subject to the jurisdiction of certain local and state agencies, including the Wisconsin Department of Natural Resources, relating to environmental and road permits.

ITC Great Plains

Kansas

ITC Great Plains is a “public utility” 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 Oklahoma Corporation Commission to operate in Oklahoma, pursuant to Oklahoma statutes as an electric public utility providing only transmission services. The Oklahoma Corporation Commission does not exercise jurisdiction over the siting of any transmission lines.

ITC Great Plains may be subject to the regulatory oversight of Oklahoma Department of Environmental Quality for compliance with environmental standards and regulations relating to construction of proposed transmission lines.

Sources of Revenue

See “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Significant Components of Results of Operations — Revenues” for a discussion of our principal sources of revenue.

Seasonality

The cost-based Formula Rates in effect for our Regulated Operating Subsidiaries, as discussed in “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cost-Based Formula Rates with True-Up Mechanism,” mitigate the seasonality of net income for our Regulated Operating Subsidiaries. Our Regulated Operating Subsidiaries accrue or defer revenues to the extent that the actual revenue requirement for the reporting period is higher or lower, respectively, than the amounts billed relating to that reporting period. For example, to the extent that amounts billed are less than our revenue requirement for a reporting period, a revenue accrual is recorded for the difference and the difference results in no net income impact.

Operating cash flows are seasonal at our MISO Regulated Operating Subsidiaries, in that cash received for revenues is typically higher in the summer months when peak load is higher.

Principal Customers

Our principal transmission service customers are DTE Electric, Consumers Energy and IP&L, which accounted for approximately 21.4% , 23.1% and 26.6% , respectively, of our consolidated billed revenues for the year ended December 31, 2018 . 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 2016 revenue accruals and deferrals and exclude any amounts for the 2018 revenue accruals and deferrals that were included in our 2018 operating revenues, but will not be billed to our customers until 2020 . Refer to “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cost-Based Formula Rates with True-Up Mechanism” for a discussion on the difference

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between billed revenues and operating revenues. Our remaining revenues were generated from providing service to other entities such as alternative electricity suppliers, power marketers and other wholesale customers that provide electricity to end-use consumers and from transaction-based capacity reservations. Nearly all of our revenues are from transmission customers in the United States. Although we may recognize allocated revenues from time to time from Canadian entities reserving transmission over the Ontario or Manitoba interface, these revenues have not been and are not expected to be material to us.

Billing

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

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

Competition

Each of our MISO Regulated Operating Subsidiaries operates the primary transmission system in its respective service area and has limited competition for certain projects. However, the competitive environment is evolving due to the implementation of the FERC Order No. 1000. See further discussion of Order No. 1000 above under “Regulatory Environment — Federal Regulation.” For our subsidiaries focused on development opportunities for transmission investment in other service areas, the incumbent utilities or other entities with transmission development initiatives may compete with us by seeking approval to be named the party authorized to build new capital projects that we are also pursuing.

Employees

As of December 31, 2018 , we had 692 employees. We consider our relations with our employees to be good.

Environmental Matters

See “Environmental Matters” in Note 18 to the consolidated financial statements.

Available Information Under the Securities Exchange Act of 1934

Our Internet address is http://www.itc-holdings.com . Visit our website to learn more about us. Financial and other material information regarding us is routinely posted on our website and is readily accessible. All of our reports filed pursuant to Section 13(a) or 15(d) of the Exchange Act, including our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports, can be accessed free of charge through our website. These reports are available as soon as practicable after they are electronically filed with the SEC. The information on our website is not incorporated by reference into this report.

ITEM 1A.      RISK FACTORS.

Risks Related to Our Business

Certain elements of our Regulated Operating Subsidiaries’ Formula Rates have been and can be challenged, which could result in lowered rates and/or refunds of amounts previously collected and thus may have an adverse effect on our business, financial condition, results of operations and cash flows.

Our Regulated Operating Subsidiaries provide transmission service under rates regulated by the FERC. The FERC has approved the cost-based Formula Rates used by our Regulated Operating Subsidiaries to calculate their respective annual revenue requirements, but it has not expressly approved the amount of actual capital and operating expenditures to be used in the Formula Rates. All aspects of our Regulated Operating Subsidiaries’ rates approved by the FERC, including the Formula Rate templates, the rates of return on the actual equity portion of their respective capital structures and the approved capital structures, are subject to challenge by interested parties at the FERC, or by the FERC on its own initiative in a proceeding under Section 206 of the FPA. In addition, interested parties may challenge the annual implementation and calculation by our Regulated Operating Subsidiaries of their projected rates and Formula Rate true up pursuant to their approved Formula Rates under the Regulated Operating Subsidiaries’ Formula Rate implementation protocols. End-use consumers and entities

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supplying electricity to end-use consumers may also attempt to influence government and/or regulators to change the rate setting methodologies that apply to our Regulated Operating Subsidiaries, particularly if rates for delivered electricity increase substantially. If a challenger can establish that any of these aspects are unjust, unreasonable, unduly discriminatory or preferential, then the FERC will make adjustments to them and/or disallow any of our Regulated Operating Subsidiaries’ inclusion of those aspects in the rate setting formula. This could result in lowered rates and/or refunds of amounts collected, any of which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Complaints have been filed against our MISO Regulated Operating Companies and we have adjusted revenues downward to accrue for anticipated refund liabilities based on our estimate of the outcome of various complaints, which had a negative effect on our results of operations for those periods. Upon final resolution of matters currently before the FERC, there may be a reduction of our future revenues and net income and a further 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 incur expenses related to the pursuit of development opportunities, which may be higher than forecasted.

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

Any capital investment at our Regulated Operating Subsidiaries may be lower than our published estimates due to, among other factors, the impact of actual loads, forecasted loads, regional economic conditions, weather conditions, union strikes, labor shortages, material and equipment prices and availability, our ability to obtain financing for such expenditures, if necessary, limitations on the amount of construction that can be undertaken on our system or transmission systems owned by others at any one time, regulatory requirements relating to our rate construct, environmental issues, siting, regional planning, cost recovery or other issues, or as a result of legal proceedings and variances between estimated and actual costs of construction contracts awarded and the potential for greater competition. Our ability to engage in construction projects resulting from pursuing these initiatives is subject to significant uncertainties, including the factors discussed above, and will depend on obtaining any necessary regulatory and other approvals for the project and for us to initiate construction, our achieving status as the builder of the project in some circumstances and other factors. In addition, projects may be canceled, the scope of planned projects may change, or projects may not be completed on time, any of which may adversely affect our level of investment or cause our projected investments to be inaccurate.

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

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

Each of our Regulated Operating Subsidiaries is a “public utility” under the FPA and, accordingly, is subject to regulation by the FERC. Approval of the FERC is required under Section 203 of the FPA for a disposition or acquisition of regulated public utility facilities, either directly or indirectly through a holding company. Such approval is also required to acquire a significant interest in securities of a public utility. Section 203 of the FPA also provides the FERC with explicit authority over utility holding companies’ purchases or acquisitions of, and mergers or consolidations with, a public utility. Finally, each of our Regulated Operating Subsidiaries must also seek approval by the FERC under Section 204 of the FPA for issuances of its securities (including debt securities). If we are unable to obtain the necessary FERC approvals for potential acquisitions, dispositions or merger activities, or to raise capital, our strategic and growth opportunities may be limited. This could have an adverse impact on our consolidated results of operations, cash flows and financial condition.

We are also pursuing development projects for construction of transmission facilities and interconnections with generating resources. These projects may require regulatory approval by Federal agencies, including the FERC, applicable RTOs and state and local regulatory agencies. Failure to secure such regulatory approval for new

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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.

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

We are subject to taxation by various taxing authorities at the federal, state and local levels. The TCJA enacted significant changes to the Internal Revenue Code including reducing the U.S. federal corporate income tax rate and providing modifications to bonus depreciation rules and limitations on the deductibility of interest expense, both of which include carve-outs for regulated utilities. These modifications and other aspects of the TCJA are still subject to interpretation and clarification. We cannot predict the timing or impacts of any future TCJA modifications or changes in tax laws, including the impacts of any subsequent technical corrections or clarifications. Increases in federal, state or local tax rates or modifications and changes in tax laws, including the TCJA, could materially and adversely affect our results of operations, net income, financial condition, cash flows, and credit metrics.

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, SPP or PJM. We cannot predict whether the approved rate methodologies for any of our Regulated Operating Subsidiaries will be changed. In addition, the U.S. Congress periodically considers enacting energy legislation that could assign new responsibilities to the FERC, modify provisions of the FPA or provide the FERC or another entity with increased authority to regulate transmission matters. Our Regulated Operating Subsidiaries may be affected by any such changes in federal energy laws, regulations or policies in the future. While our Regulated Operating Subsidiaries are subject to the FERC’s exclusive jurisdiction for purposes of rate regulation, changes in state laws affecting other matters, such as transmission siting and construction, could limit investment opportunities available to us.

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

ITCTransmission derives a substantial portion of its revenues from the transmission of electricity to DTE Electric’s local distribution facilities. DTE Electric accounted for approximately 62.9% of ITCTransmission’s total billed revenues for the year ended December 31, 2018 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 S&P and Moody’s, respectively. Similarly, Consumers Energy accounted for approximately 83.5% of METC’s total billed revenues for the year ended December 31, 2018 and is expected to constitute the majority of METC’s revenues for the foreseeable future. Consumers Energy is rated BBB+/stable and A2/stable by S&P and Moody’s, respectively. Further, IP&L accounted for approximately 69.7% of ITC Midwest’s total billed revenues for the year ended December 31, 2018 and is expected to constitute the majority of ITC Midwest’s revenues for the foreseeable future. IP&L is rated A-/negative and Baa1/negative by S&P and Moody’s, respectively. These percentages of total billed revenues of DTE Electric, Consumers Energy and IP&L include the collection of 2016 revenue accruals and deferrals and exclude any amounts for the 2018 revenue accruals and deferrals that were included in our 2018 operating revenues, but will not be billed to our customers until 2020 .

Any material failure by DTE Electric, Consumers Energy or IP&L to make payments for transmission services could have an adverse effect on our business, financial condition, results of operations and cash flows.

A significant amount of the land on which our assets are located is subject to easements, mineral rights and other similar encumbrances. As a result, we must comply with the provisions of various easements, mineral rights and other similar encumbrances, which may adversely impact our ability to complete construction projects in a timely manner.

METC does not own the majority of the land on which its electric transmission assets are located. Instead, under the provisions of the Easement Agreement, METC pays an annual rent to Consumers Energy in exchange for rights-of-way, leases, fee interests and licenses which allow METC to use the land on which its transmission lines are located. Under the terms of the Easement Agreement, METC’s easement rights could be eliminated if METC fails to meet certain requirements, such as paying contractual rent to Consumers Energy in a timely manner.

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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, costly litigation or the imposition of civil or criminal penalties.

Our operations are subject to the usual hazards associated with high-voltage electricity transmission, including explosions, fires, mechanical failure, unscheduled downtime, equipment interruptions, remediation, chemical spills, discharges or releases of toxic or hazardous substances or gases and other environmental risks. These hazards can cause personal injury and loss of life, severe damage to or destruction of property and equipment and environmental damage, and may result in suspension of operations, litigation by aggrieved parties and the imposition of civil or criminal penalties which may have a material adverse effect on our business, financial condition and results of operations. We maintain property and casualty insurance, but we are not fully insured against all potential hazards incident to our business, such as damage to poles, towers and lines or losses caused by outages.

We are subject to environmental regulations and to laws that can give rise to substantial liabilities from environmental contamination.

We are subject to federal, state and local environmental laws and regulations, which impose limitations on the discharge of pollutants into the environment, establish standards for the management, treatment, storage, transportation and disposal of solid and hazardous wastes and hazardous materials, and impose obligations to investigate and remediate contamination in certain circumstances. Liabilities relating to investigation and remediation of contamination, as well as other liabilities concerning hazardous materials or contamination such as claims for personal injury or property damage, may arise at many locations, including formerly owned or operated properties and sites where wastes have been treated or disposed of, as well as properties we currently own or operate. Such liabilities may arise even where the contamination does not result from noncompliance with applicable environmental laws. Under a number of environmental laws, such liabilities may also be joint and several, meaning that a party can be held responsible for more than its share of the liability involved, or even the entire share. Environmental requirements generally have become more stringent in recent years, and compliance with those requirements more expensive.

We have incurred expenses in connection with environmental compliance, and we anticipate that we will continue to do so in the future. Failure to comply with the extensive environmental laws and regulations applicable to us could result in significant civil or criminal penalties and remediation costs. Our assets and operations also involve the use of materials classified as hazardous, toxic or otherwise dangerous. Some of our facilities and properties are located near environmentally sensitive areas such as wetlands and habitats of endangered or threatened species. In addition, certain properties in which we operate are, or are suspected of being, affected by environmental contamination. Compliance with these laws and regulations, and liabilities concerning contamination or hazardous materials, may adversely affect our costs and, therefore, our business, financial condition and results of operations.

If amounts billed for transmission service for our Regulated Operating Subsidiaries’ transmission systems are lower than expected, or our actual revenue requirements are higher than expected, the timing of actual collection of our total revenues would be delayed.

If amounts billed for transmission service are lower than expected, the timing of actual collections of our Regulated Operating Subsidiaries’ total revenue requirement would likely be delayed until such circumstances are adjusted through the true-up mechanism, which would be settled within a two-year period, in our Regulated Operating Subsidiaries’ Formula Rates. Lower than expected amounts collected could result from lower network

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load or point-to-point transmission service on our Regulated Operating Subsidiaries’ transmission systems due to a weak economy, changes in the nature or composition of the transmission assets of our Regulated Operating Subsidiaries and surrounding areas, poor transmission quality of neighboring transmission systems, or for any other reason. In addition, if the revenue requirements of our Regulated Operating Subsidiaries are higher than expected, the timing of actual collection of our Regulated Operating Subsidiaries' total revenue requirements would likely be delayed until such circumstances are reflected through the true-up mechanism, which would be settled within a two-year period, in our Regulated Operating Subsidiaries' Formula Rates. This could be due to higher actual expenditures compared to the forecasted expenditures used to develop their billing rates or for any other reason. The effect of such under-collection would be to reduce the amount of our available cash resources from what we had expected, until such under-collection is corrected through the true-up mechanism in the Formula Rate template, which may require us to increase our outstanding indebtedness, thereby reducing our available borrowing capacity, and may require us to pay interest at a rate that exceeds the interest to which we are entitled in connection with the operation of the true-up mechanism.

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

The various regulatory requirements to which we are subject include reliability standards established by the NERC, which acts as the nation’s Electric Reliability Organization approved by the FERC in accordance with Section 215 of the FPA. These standards address operation, planning and security of the bulk power system, including requirements with respect to real-time transmission operations, emergency operations, vegetation management, critical infrastructure protection and personnel training. Failure to comply with these requirements can result in monetary penalties as well as non-monetary sanctions. Monetary penalties vary based on an assigned risk factor for each potential violation, the severity of the violation and various other circumstances, such as whether the violation was intentional or concealed, whether there are repeated violations, the degree of the violator’s cooperation in investigating and remediating the violation and the presence of a compliance program, and such penalties can be substantial. Non-monetary sanctions include potential limitations on the violator’s activities or operation and placing the violator on a watchlist for major violators. If any of our subsidiaries 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 the FERC policy, failure to file jurisdictional agreements on a timely basis may result in foregoing the time value of revenues collected under the agreement, but not to the point where a loss would be incurred. The failure to obtain timely approval of transactions subject to FPA Section 203, or to comply with applicable reporting, recordkeeping or accounting requirements under FPA Section 205, could subject us to penalties that could have a material adverse effect on our financial condition, results of operations and cash flows.

Acts of war, terrorist attacks, natural disasters, severe weather and other catastrophic events may have a material adverse effect on our business, financial condition, results of operations and cash flows.

Acts of war, terrorist attacks, natural disasters, severe weather and other catastrophic events may negatively affect our business, financial condition and cash flows in unpredictable ways, such as increased security measures and disruptions of markets. Energy related assets, including, for example, our transmission facilities and DTE Electric’s, Consumers Energy’s and IP&L’s generation and distribution facilities that we interconnect with, may be at risk of acts of war and terrorist attacks, as well as natural disasters, severe weather and other catastrophic events. Such events or threats may have a material effect on the economy in general and could result in a decline in energy consumption, which may have a material adverse effect on our business, financial condition, results of operations and cash flows.

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A cyber attack or incident could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Various U.S. Government agencies have noted that external threat sources continue to seek to exploit, through cyber attacks, potential vulnerabilities in the U.S. energy infrastructure including electric transmission assets. These cyber threats and attacks are becoming more sophisticated and dynamic. Cyber security incidents could harm our business by limiting our transmission capabilities, delay our development and construction of new facilities or capital improvement projects on existing facilities or expose us to liability. Cyber attacks targeting our information systems could also impair our records, networks, systems and programs, or transmit viruses to other systems. Such events or the threat of such events may increase costs associated with heightened security requirements. In addition, if our major customers or suppliers experience a cyber attack it may reduce their ability to use our transmission facilities or service our transmission assets. If our business or those of our customers and suppliers are subject to a cyber attack, it may have a material adverse effect on our business, financial condition, results of operations and cash flows.

Risks Relating to Our Corporate and Financial Structure

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

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

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

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

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

•	We may need to increase our indebtedness in order to make the capital expenditures and other expenses or investments planned by us.

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

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

•	We currently have debt instruments outstanding with short-term maturities or relatively short remaining maturities. Our ability to secure additional financing prior to or after these facilities mature, if needed, may be substantially restricted by the existing level of our indebtedness and the restrictions contained in our debt

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instruments. Additionally, the interest rates at which we might secure additional financings may be higher than our currently outstanding debt instruments or higher than forecasted at any point in time, which could adversely affect our business, financial condition, results of operations and cash flows.

•	Market conditions could affect our access to capital markets, restrict our ability to secure financing to make the capital expenditures and investments and pay other expenses planned by us which could adversely affect our business, financial condition, cash flows and results of operations.

We may incur substantial additional indebtedness in the future. The incurrence of additional indebtedness would increase the leverage-related risks described above.

Adverse changes in our credit ratings may negatively affect us.

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

Certain provisions in our debt instruments limit our financial and operating flexibility.

Our debt instruments on a consolidated basis, including senior notes, secured notes, first mortgage bonds, revolving and term loan credit agreements and commercial paper, contain numerous financial and operating covenants that place significant restrictions on, among other things, our ability to:

•	incur additional indebtedness;

•	engage in sale and lease-back transactions;

•	create liens or other encumbrances;

•	enter into mergers, consolidations, liquidations or dissolutions, or sell or otherwise dispose of all or substantially all of our assets;

•	create and acquire subsidiaries; and

•	pay dividends or make distributions on our stock or on the stock or member capital of our subsidiaries.

In addition, the covenants require us to meet certain financial ratios, such as maintaining certain net debt to capitalization ratios and certain funds from operations to net debt levels. Our ability to comply with these and other requirements and restrictions may be affected by changes in economic or business conditions, results of operations or other events beyond our control. A failure to comply with the obligations contained in any of our debt instruments could result in acceleration of related debt and the acceleration of debt under other instruments evidencing indebtedness that may contain cross-acceleration or cross-default provisions.

ITEM 1B.      UNRESOLVED STAFF COMMENTS.

None.

ITEM 2.     PROPERTIES.

Our Regulated Operating Subsidiaries’ transmission facilities are located in Michigan and portions of Iowa, Minnesota, Illinois, Missouri, Kansas and Oklahoma. Our MISO Regulated Operating Subsidiaries and ITC Great Plains have agreements with other utilities for the joint ownership of specific substations, transmission lines and other transmission assets. See Note 16 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;

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•	approximately 18,800 transmission towers and poles;

•	station assets, such as transformers and circuit breakers, at 196 stations and substations which either interconnect ITCTransmission’s transmission facilities or connect ITCTransmission’s facilities with generation or distribution facilities owned by others;

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

•	warehouses and related equipment;

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

•	an approximately 198,000 square-foot corporate headquarters facility and operations control room in Novi, Michigan, including furniture, fixtures and office equipment; and

•	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 37,100 transmission towers and poles;

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

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

•	warehouses and related equipment.

METC's Senior Secured Notes are issued under METC's first mortgage indenture. As a result, the noteholders have the benefit of a first mortgage lien on substantially all of METC's property.

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

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

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

•	transmission towers and poles;

•	station assets, such as transformers and circuit breakers, at approximately 284 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.

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ITC Great Plains owns transmission and related assets, including:

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

•	approximately 2,120 transmission towers and poles;

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

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

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

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

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, 2018 , there were no liens or encumbrances on the assets of ITC Interconnection.

The assets of our Regulated Operating Subsidiaries are suitable for electric transmission and adequate for the electricity demand in our service territory. We prioritize capital spending based in part on meeting reliability standards within the industry. This includes replacing and upgrading existing assets as needed.

ITEM 3.      LEGAL PROCEEDINGS.

We are involved in certain legal proceedings before various courts, governmental agencies and mediation panels concerning matters arising in the ordinary course of business. These proceedings include certain contract disputes, regulatory matters and pending judicial matters. We cannot predict the final disposition of such proceedings. We regularly review legal matters and record provisions for claims that are considered probable of loss.

Refer to Notes 6 and 18 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.

Additionally, ITC Holdings paid dividends of $200 million and $300 million to our parent, Investment Holdings, during the years ended December 31, 2018 and 2017, respectively. ITC Holdings also paid dividends of $73 million to Investment Holdings in January 2019. The timing and amount of future dividends is subject to an approved dividend declaration from our Board of Directors, and is dependent upon cash flows, capital requirements, legislative and regulatory developments, and financial condition of ITC Holdings, among other factors deemed relevant.

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ITEM 6.      SELECTED FINANCIAL DATA.

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

	ITC Holdings and Subsidiaries
	Year Ended December 31,
(In millions)	2018				2017				2016				2015				2014
OPERATING REVENUES (a) (b)
Transmission and other services	$	1,192			$	1,226			$	1,142			$	1,025			$	1,044
Formula Rate true-up	(36		)		(15		)		(17		)		20				(21		)
Total operating revenue	1,156				1,211				1,125				1,045				1,023
OPERATING EXPENSES
Operation and maintenance	109				110				114				113				112
General and administrative (c) (d) (e)	127				121				234				140				113
Depreciation and amortization	180				169				158				145				128
Taxes other than income taxes	109				103				93				82				76
Other operating (income) and expense, net	(4		)		(2		)		(1		)		(1		)		(1		)
Total operating expenses (e)	521				501				598				479				428
OPERATING INCOME (e)	635				710				527				566				595
OTHER EXPENSES (INCOME)
Interest expense, net (f)	224				224				211				204				216
Allowance for equity funds used during construction	(33		)		(33		)		(35		)		(28		)		(21		)
Other (income) and expenses, net (e)	3				4				8				6				6
Total other expenses (income) (e)	194				195				184				182				201
INCOME BEFORE INCOME TAXES	441				515				343				384				394
INCOME TAX PROVISION (g)	111				196				97				142				150
NET INCOME	$	330			$	319			$	246			$	242			$	244

____________________________

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

(b)	We recognized a reduction in operating revenues of $80 million , $115 million and $47 million in 2016, 2015 and 2014, respectively relating to the rate of return on equity complaints as described in Note 18 to the consolidated financial statements.

(c)

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 1 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.

(d)

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

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

(f)	During 2014, we recorded loss on extinguishment of debt of $29 million related to a cash tender offer for the retirement of debt at ITC Holdings.

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

	ITC Holdings and Subsidiaries
	As of December 31,
(In millions)	2018				2017				2016				2015				2014
BALANCE SHEET DATA:
Cash and cash equivalents	$	6			$	66			$	8			$	14			$	28
Working capital (deficit) (a)	(308		)		(302		)		(400		)		(550		)		(291		)
Property, plant and equipment, net	7,910				7,309				6,698				6,110				5,497
Goodwill	950				950				950				950				950
Total assets (a) (b)	9,329				8,823				8,223				7,555				6,932
Debt:
ITC Holdings (b)	2,767				2,728				2,387				2,304				2,123
Regulated Operating Subsidiaries (b)	2,571				2,373				2,203				2,125				1,954
Total debt (b)	5,338				5,101				4,590				4,429				4,077
Total stockholder’s equity	$	2,051			$	1,920			$	1,901			$	1,709			$	1,670

____________________________

(a)	All amounts presented reflect the change in the authoritative guidance issued by the FASB 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.

(b)	All amounts presented reflect the change in authoritative guidance on the presentation of debt issuance costs on the balance sheet. This change was adopted retrospectively by us in 2015.

	ITC Holdings and Subsidiaries
	Year Ended December 31,
(In millions)	2018				2017				2016				2015				2014
CASH FLOWS DATA:
Expenditures for property, plant and equipment	$	769			$	755			$	750			$	701			$	753

ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

Safe Harbor Statement Under The Private Securities Litigation Reform Act of 1995

Our reports, filings and other public announcements contain certain statements that describe our management’s beliefs concerning future business conditions, plans and prospects, growth opportunities, the outlook for our business and the electric transmission industry, and expectations with respect to various legal and regulatory proceedings based upon information currently available. Such statements are “forward-looking” statements within the meaning of the Private Securities Litigation Reform Act of 1995. Wherever possible, we have identified these forward-looking statements by words such as “will,” “may,” “anticipates,” “believes,” “intends,” “estimates,” “expects,” “forecasted,” “projects,” “likely” and similar phrases. These forward-looking statements are based upon assumptions our management believes are reasonable. Such forward-looking statements are based on estimates and assumptions and subject to significant risks and uncertainties which could cause our actual results, performance and achievements to differ materially from those expressed in, or implied by, these statements, including, among others, the risks and uncertainties listed in this report under “Item 1A Risk Factors” and in our other reports filed with the SEC from time to time.

Forward-looking statements speak only as of the date made and can be affected by assumptions we might make or by known or unknown risks and uncertainties. Many factors mentioned in our discussion in this report will be important in determining future results. Consequently, we cannot assure you that our expectations or forecasts expressed in such forward-looking statements will be achieved. Except as required by law, we undertake no

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obligation to publicly update any of our forward-looking or other statements, whether as a result of new information, future events or otherwise.

Overview

ITC Holdings and its subsidiaries are engaged in the transmission of electricity in the United States. ITC Holdings is a wholly-owned subsidiary of Investment Holdings. Through our Regulated Operating Subsidiaries, we own and operate high-voltage systems in Michigan’s Lower Peninsula and portions of Iowa, Minnesota, Illinois, Missouri, Kansas and Oklahoma that transmit electricity from generating stations to local distribution facilities connected to our systems. Our business strategy is to own, operate, maintain and invest in transmission infrastructure in order to enhance system integrity and reliability, reduce transmission constraints and support new generating resources to interconnect to our transmission systems. We also are pursuing development projects outside our existing systems.

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

Our Regulated Operating Subsidiaries’ primary operating responsibilities include maintaining, improving and expanding their transmission systems to meet their customers’ ongoing needs, scheduling outages on system elements to allow for maintenance and construction, maintaining appropriate system voltages and monitoring flows over transmission lines and other facilities to ensure physical limits are not exceeded.

Significant recent matters that influenced our financial position, results of operations and cash flows for the year ended December 31, 2018 or that may affect future results include:

•	The change in federal tax rate arising from the enactment of the TCJA, which resulted in reductions to revenue requirements and payments of the 2018 resettlement obligation in connection with the reposting of the 2018 rates, as described below under “— Recent Developments;”

•	Our capital expenditures of $769 million at our Regulated Operating Subsidiaries during the year ended December 31, 2018 , as described below under “— Capital Investment and Operating Results Trends,” resulting primarily from our focus on improving system reliability, increasing system capacity and upgrading the transmission network to support new generating resources;

•	Debt issuances and repayments as described in Note 10 to the consolidated financial statements, including the issuance of First Mortgage bonds by ITCTransmission and ITC Midwest and borrowings under our revolving credit agreements to fund capital investment at our Regulated Operating Subsidiaries as well as for general corporate purposes;

•	Our MISO Regulated Operating Subsidiaries had an estimated current regulatory liability of $151 million as of December 31, 2018 for the potential refund relating to the Second Complaint as described in Note 18 to the consolidated financial statements.

These items are discussed in more detail throughout “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Cost-Based Formula Rates with True-Up Mechanism

Our Regulated Operating Subsidiaries calculate their revenue requirements using cost-based Formula Rates that are effective without the need to file rate cases with the FERC, although the rates are subject to legal challenge at the FERC. Under their cost-based formula, each of our Regulated Operating Subsidiaries separately calculates a revenue requirement based on financial information specific to each company. The calculation of projected revenue requirement for a future period is used to establish the transmission rate used for billing purposes. The calculation of actual revenue requirements for a historic period is used to calculate the amount of revenues recognized in that period and determine the over- or under-collection for that period.

Under these Formula Rates, our Regulated Operating Subsidiaries recover expenses and earn a return on and recover investments in property, plant and equipment on a current basis . The Formula Rates for a given year reflect

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forecasted expenses, property, plant and equipment, point-to-point revenues, network load at our MISO Regulated Operating Subsidiaries and other items for the upcoming calendar year to establish projected revenue requirements for each of our Regulated Operating Subsidiaries that are used as the basis for billing for service on their systems from January 1 to December 31 of that year. Our Formula Rates include a true-up mechanism, whereby our Regulated Operating Subsidiaries compare their actual revenue requirements to their billed revenues for each year to determine any over- or under-collection of revenue. The over- or under-collection typically results from differences between the projected revenue requirement used as the basis for billing and actual revenue requirement at each of our Regulated Operating Subsidiaries, or from differences between actual and projected monthly peak loads at our MISO Regulated Operating Subsidiaries. In the event billed revenues in a given year are more or less than actual revenue requirements, which are calculated primarily using information from that year’s FERC Form No. 1, our Regulated Operating Subsidiaries will refund or collect additional revenues, with interest, within a two-year period such that customers pay only the amounts that correspond to actual revenue requirements for that given period. This annual true-up ensures that our Regulated Operating Subsidiaries recover their allowed costs and earn their allowed returns.

See “Cost-Based Formula Rates with True-Up Mechanism” in Note 6 to the consolidated financial statements for further discussion of our Formula Rates and see “Rate of Return on Equity Complaints” in Note 18 to the consolidated financial statements for detail on ROE matters.

Illustrative Example of Formula Rate Setting

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

Line	Item	Instructions	Amount
1	Rate base (a)		$	1,000,000
2	Multiply by 13-month weighted average cost of capital (b)		8.64		%
3	Allowed return on rate base	(Line 1 x Line 2)	$	86,400
4	Recoverable operating expenses (including depreciation and amortization)		$	150,000
5	Income taxes (c)		37,500
6	Gross revenue requirement	(Line 3 + Line 4 + Line 5)	$	273,900

____________________________

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

(b)

The weighted average cost of capital for purposes of this illustration is calculated below. The cost of capital for debt is included at a flat interest rate for purposes of this illustration and is not based on our actual cost of capital. The cost of capital rate for equity represents the current maximum allowed MISO ROE per the September 2016 order on the Initial Complaint. See Note 18 to the consolidated financial statements for detail on ROE matters, including pending ROE complaints.

					Weighted
					Average
	Percentage of				Cost of
	Total Capitalization		Cost of Capital		Capital
Debt	40.00%		5.00% =		2.00	%
Equity	60.00%		11.07% =		6.64	%
	100.00%				8.64	%

(c)	Represents an approximation of the federal and state income tax expense for purposes of this illustration and is not based on our actual tax expense.

Revenue Accruals and Deferrals — Effects of Monthly Peak Loads

For our MISO Regulated Operating Subsidiaries, monthly peak loads are used for billing network revenues, which currently is the largest component of our operating revenues. One of the primary factors that impacts the revenue accruals and deferrals at our MISO Regulated Operating Subsidiaries is actual monthly peak loads experienced as compared to those forecasted in establishing the annual network transmission rate. Under their cost-based Formula Rates that contain a true-up mechanism, our MISO Regulated Operating Subsidiaries accrue

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or defer revenues to the extent that their actual revenue requirement for the reporting period is higher or lower, respectively, than the amounts billed relating to that reporting period. Although monthly peak loads do not impact operating revenues recognized, network load affects the timing of our cash flows from transmission service. The monthly peak load of our MISO Regulated Operating Subsidiaries is generally impacted by weather and economic conditions and seasonally shaped with higher load in the summer months when cooling demand is higher.

ITC Great Plains does not receive revenue based on a peak load or a dollar amount per kW each month therefore, peak load does not have a seasonal effect on operating cash flows. The SPP tariff applicable to ITC Great Plains is billed ratably each month based on its annual projected revenue requirement posted annually by SPP.

Capital Investment and Operating Results Trends

We expect a long-term upward trend in 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 18 and Note 6 to the consolidated financial statements;

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

•	lower net income due to lower interest expense deductibility as a result of a lower federal tax rate at ITC Holdings under the TCJA.

The primary factor that is expected to continue to increase our revenues and earnings in future years is increased rate base that would result from our anticipated capital investment, in excess of depreciation, from our Regulated Operating Subsidiaries’ long-term capital investment programs to improve reliability, increase system capacity and upgrade the transmission network to support new generating resources. Investments in property, plant and equipment, when placed in-service upon completion of a capital project, are added to the rate base of our Regulated Operating Subsidiaries.

Our Regulated Operating Subsidiaries strive for high reliability of their systems and improvement in system accessibility for all generation resources. The FERC requires compliance with certain reliability standards and may take enforcement actions against violators, including the imposition of substantial fines. NERC is responsible for developing and enforcing these mandatory reliability standards. We continually assess our transmission systems against standards established by NERC, as well as the standards of applicable regional entities under NERC that have been delegated certain authority for the purpose of proposing and enforcing reliability standards. We believe that we meet the applicable standards in all material respects, although further investment in our transmission systems and an increase in maintenance activities will likely be needed to maintain compliance, improve reliability and address any new standards that may be promulgated.

We also assess our transmission systems against our own planning criteria that are filed annually with the FERC. Based on our planning studies, we see needs to make capital investments to: (1) maintain and replace the current transmission infrastructure; (2) enhance system integrity and reliability and accommodate load growth; (3) upgrade physical and technological grid security; and (4) develop and build regional transmission infrastructure, including additional transmission facilities that will provide interconnection opportunities for generating facilities. The following table shows our actual and expected capital expenditures at our Regulated Operating Subsidiaries:

		Actual Capital				Forecasted
		Expenditures for the				Capital
		year ended				Expenditures
(In millions)		December 31, 2018				2019 — 2023
Expenditures for property, plant and equipment (a)		$	769			$	3,515

____________________________

(a)	Amounts represent the cash payments to acquire or construct property, plant and equipment, as presented in the consolidated statements of cash flows . These amounts exclude non-cash additions to property, plant and equipment for the AFUDC equity as well as accrued liabilities for construction, labor and materials that have not yet been paid.

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We are pursuing development projects that could result in a significant amount of capital investment, but we are not able to estimate the amounts we ultimately expect to invest or the timing of such investments. Our capital investment efforts relating to development initiatives are based on establishing an ongoing pipeline of projects that would position us for long-term growth. Refer to “Item 1 Business — Development of Business” for discussion of our development activities.

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

Impacts of the TCJA

In December 2017, the President of the United States of America signed into law the TCJA, which enacted significant changes to the Internal Revenue Code including a reduction in the U.S. federal corporate income tax rate from 35% to 21% effective for tax years beginning after 2017. The lower federal tax rate resulted in a reduction to the revenue requirement of $105 million at our Regulated Operating Subsidiaries for 2018. This reduction was reflected in 2018 projected Formula Rates that were reposted for our MISO Regulated Operating Subsidiaries and ITC Great Plains during 2018.

In December 2017, we revalued our deferred tax assets and liabilities at the lower U.S. federal corporate income tax rate implemented through enactment of the TCJA. The revaluation of the net deferred taxes resulted in a net regulatory liability and a reduction in regulatory assets at our Regulated Operating Subsidiaries that will be returned to or received from customers over future periods. During 2018, we began to amortize the net regulatory liability related to the excess deferred taxes. We recorded less than $1 million of amortization during 2018, as the net regulatory liability is primarily associated with public utility property with long estimated remaining lives and the amortization is recorded ratably over the estimated book lives of those assets. We do not expect to record significant amounts of amortization over the next several years.

On March 15, 2018, the FERC granted a waiver which allowed us to adjust the rates effective back to January 1, 2018 for our MISO Regulated Operating Subsidiaries and allowed MISO to return to customers excess amounts previously collected in 2018. Our rates included in MISO invoices for services provided starting in March 2018 and going forward reflected the lower corporate tax rate. Resettlement of invoices for services provided in January and February 2018 occurred in April 2018 when the March 2018 services were billed. We recorded a reduction of revenue of $16 million in the first quarter of 2018, which was offset through a lower income tax provision for our MISO Regulated Operating Subsidiaries and as such did not impact net income.

On May 25, 2018, the FERC granted a waiver which allowed us to adjust the rate effective back to January 1, 2018 for ITC Great Plains and allowed SPP to return to customers excess amounts previously collected in 2018. Our rates included in SPP invoices for services provided starting in June and going forward reflected the lower corporate tax rate. During the second quarter of 2018, we recorded a reduction of revenue of $4 million related to the resettlement of invoices for services provided in January through May 2018. Resettlement of these invoices occurred during the fourth quarter of 2018. This reduction of revenue was offset through a lower income tax provision for ITC Great Plains and as such did not impact net income.

For additional information on the impacts of tax reform, see below under “— Results of Operations”, as well as Note 7 and Note 11 to the consolidated financial statements .

Rate of Return on Equity Complaints

Two complaints have been filed with the FERC by combinations of consumer advocates, consumer groups, municipal parties and other parties challenging the base ROEs in MISO. See Note 18 to the consolidated financial statements for a summary of the complaints and related proceedings.

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In 2017, $118 million , including interest, was refunded to customers of our MISO Regulated Operating Subsidiaries for the Initial Complaint based on the refund liability associated with the September 2016 Order. As of December 31, 2018, we had recorded an aggregate estimated current regulatory liability in the consolidated statements of financial position of $151 million for the Second Complaint. The recognition of the obligations associated with the complaints resulted in the following impacts:

	Year Ended December 31,
(In millions)	2018				2017				2016
Revenue reduction	$	(1	)		$	—			$	80
Interest expense increase	7				6				10
Estimated net income reduction (a)	4				3				55

____________________________

(a)	Includes an effect on net income of $27 million for the year ended December 31, 2016 for revenue initially recognized in 2015, 2014 and 2013.

Prior to the filing of the MISO ROE complaints, complaints were filed with the FERC regarding the regional base ROE rate for ISO New England TOs. In resolving these complaints, the FERC adopted a methodology for establishing base ROE rates based on a two-step DCF analysis. This methodology provided the precedent for the FERC ruling on the Initial Complaint and the ALJ initial decision on the Second Complaint for our MISO Regulated Operating Subsidiaries. In April 2017, the D.C. Circuit Court vacated the precedent-setting FERC orders that established and applied the two-step DCF methodology for the determination of base ROE. The court remanded the orders to the FERC for further justification of its establishment of the new base ROE for the ISO New England TOs. On October 16, 2018, in the New England matters, the FERC issued an order on remand which proposes a new methodology for 1) determining when an existing ROE is no longer just and reasonable; and 2) setting a new just and reasonable ROE if an existing ROE has been found not to be just and reasonable. The FERC established a paper hearing on how the proposed new methodology should apply to the ISO New England TOs ROE complaint proceedings. The FERC issued a similar order, the November 2018 Order, in the MISO TO base ROE complaint proceedings establishing a paper hearing on the application of the proposed new methodology to the proceedings pending before the FERC involving the MISO TOs’ ROE, including our MISO Regulated Operating Subsidiaries. Briefs in the New England proceedings were filed on January 11, 2019 and briefs in the MISO proceedings were filed on February 13, 2019. Reply briefs for both the MISO and New England matters are due to be filed during the first half of 2019.

The November 2018 Order included illustrative calculations for the ROE that may be established for the Initial Complaint, using the FERC's proposed methodology with financial data from the proceedings related to that complaint. If the results of these illustrative calculations are confirmed in a final FERC order, then the application of the base ROE and the maximum ROE would not have a significant adverse impact on our financial condition, results of operations and cash flows.

Although the November 2018 Order provided illustrative calculations, the FERC stated that these calculations are merely preliminary. The FERC’s preliminary calculations are not binding and could change, as significant changes to the methodology by the FERC are possible as a result of the paper hearing process. Until there is more certainty around the ultimate resolution of these matters, we cannot reasonably update an estimated range of gain or loss for any of the complaint proceedings or estimate a range of gain or loss for the period subsequent to the end of the Second Complaint refund period. The November 2018 Order and our response to the order through briefs filed on February 13, 2019 do not provide a reasonable basis for a change to the reserve or recognized ROEs for any of the complaint refund periods nor all subsequent periods, and we believe that the risk of additional material loss beyond amounts already accrued is remote.

Our MISO Regulated Operating Subsidiaries currently record revenues at the base ROE of 10.32% established in the September 2016 Order on the Initial Complaint plus applicable incentive adders. See Note 6 to the consolidated financial statements for a summary of incentive adders for transmission rates.

As of December 31, 2018, our MISO Regulated Operating Subsidiaries had a total of approximately $4 billion of equity in their collective capital structures for ratemaking purposes. Based on this level of aggregate equity, we estimate that each 10 basis point change in the authorized ROE would impact annual consolidated net income by approximately $4 million .

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Challenges to Incentive Adders for Transmission Rates

See Note 6 to the consolidated financial statements for a summary of incentive adders for transmission rates.

MISO Regulated Operating Subsidiaries

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

ITC Great Plains

On December 19, 2018, the KCC filed a Motion to Show Cause with the FERC to reduce the ITC Great Plains adder for independent transmission ownership. The motion argues that because ITC Great Plains is similarly situated to our MISO Regulated Operating Subsidiaries with respect to ownership by Fortis and GIC, the same rationale by which the FERC lowered the MISO Regulated Operating Subsidiaries adders for independent transmission ownership, as discussed above, applies with equal force to ITC Great Plains. The adder for independent transmission ownership allows up to 100 basis points to be added to the ITC Great Plains authorized ROE, subject to any ROE cap established by the FERC. On January 16, 2019, ITC Great Plains filed a motion to strike the KCC motion. We do not expect the resolution of this motion to have a material adverse impact on our consolidated results of operation, cash flows or financial condition.

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 below under “— Critical Accounting Policies and Estimates — Revenue Recognition under Cost-Based Formula Rates with True-Up Mechanism” for a discussion of revenue recognition relating to network revenues.

Network revenues from ITC Great Plains include the annual revenue requirements specific to projects that are charged exclusively within one pricing zone within SPP or are classified as direct assigned network upgrades under the SPP tariff and contain a true-up mechanism.

Regional Cost Sharing Revenues are generated from transmission customers throughout RTO regions for their use of our MISO Regulated Operating Subsidiaries’ network upgrade projects that are eligible for regional cost sharing under provisions of the MISO tariff, including MVP projects such as our portion of four MVPs and the

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Thumb Loop Project in Michigan. Additionally, certain projects at ITC Great Plains are eligible for recovery through a region-wide charge under provisions of the SPP tariff. Regional cost sharing revenues is treated as a reduction to the net network revenue requirement under our cost-based Formula Rates.

Point-to-Point Revenues consist of revenues generated from a type of transmission service for which the customer pays for transmission capacity reserved along a specified path between two points on an hourly, daily, weekly or monthly basis. Point-to-point revenues also include other components pursuant to schedules under the MISO and SPP transmission tariffs. Point-to-point revenues are treated as a revenue credit to network or regional customers and are a reduction to gross revenue requirement when calculating net revenue requirement under our cost-based Formula Rates.

Scheduling, Control and Dispatch Revenues are allocated to our MISO Regulated Operating Subsidiaries by MISO as compensation for the services performed in operating the transmission system. Such services include monitoring of reliability data, current and next day analysis, implementation of emergency procedures and outage coordination and switching.

Other Revenues consist of rental revenues, easement revenues, revenues relating to utilization of jointly owned assets under our transmission ownership and operating agreements and amounts from providing ancillary services to customers. The majority of other revenues are treated as a revenue credit and taken as a reduction to gross revenue requirement when calculating net revenue requirement under our cost-based Formula Rates.

Operating Expenses

Operation and Maintenance Expenses consist primarily of the costs for contractors that operate and maintain our transmission systems as well as our personnel involved in operation and maintenance activities.

Operation expenses include activities related to control area operations, which involve balancing loads and generation and transmission system operations activities, including monitoring the status of our transmission lines and stations. Rental expenses relating to land easements, including METC’s Easement Agreement, are also recorded within operation expenses.

Maintenance expenses include preventive or planned maintenance, such as vegetation management, tower painting and equipment inspections, as well as reactive maintenance for equipment failures.

General and Administrative Expenses consist primarily of costs for personnel in our legal, information technology, finance, regulatory, human resources and business development organizations, general office expenses and fees for professional services. Professional services are principally composed of outside legal, consulting, audit and information technology services.

Depreciation and Amortization Expenses consist primarily of depreciation of property, plant and equipment using the straight-line method of accounting. Additionally, this consists of amortization of various regulatory and intangible assets.

Taxes Other than Income Taxes consist primarily of property taxes and payroll taxes.

Other Items of Income or Expense

Interest Expense consists primarily of interest on debt at ITC Holdings and our Regulated Operating Subsidiaries. Additionally, the amortization of debt financing expenses and loss on extinguishment of debt are recorded to interest expense. An allowance for borrowed funds used during construction is included in property, plant and equipment accounts and treated as a reduction to interest expense. The amortization of gains and losses on settled and terminated derivative financial instruments is recorded to interest expense. The interest portion of the refund and estimated refund relating to the ROE complaints is also recorded to interest expense.

Allowance for Equity Funds Used During Construction (“AFUDC equity”) is recorded as an item of other income and is included in property, plant and equipment accounts. The allowance represents a return on equity at our Regulated Operating Subsidiaries used for construction purposes in accordance with the FERC regulations. The capitalization rate applied to the construction work in progress balance is based on the proportion of equity to total capital (which currently includes equity and long-term debt) and the allowed return on equity for our Regulated Operating Subsidiaries.

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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:

	Year Ended												Percentage		Year Ended								Percentage
	December 31,								Increase				Increase		December 31,				Increase				Increase
(In millions)	2018				2017				(Decrease)				(Decrease)		2016				(Decrease)				(Decrease)
OPERATING REVENUES
Transmission and other services	$	1,192			$	1,226			$	(34	)		(3)%		$	1,142			$	84			7%
Formula Rate true-up	(36		)		(15		)		(21		)		140%		(17		)		2				(12)%
Total operating revenue	1,156				1,211				(55		)		(5)%		1,125				86				8%
OPERATING EXPENSES
Operation and maintenance	109				110				(1		)		(1)%		114				(4		)		(4)%
General and administrative	127				121				6				5%		234				(113		)		(48)%
Depreciation and amortization	180				169				11				7%		158				11				7%
Taxes other than income taxes	109				103				6				6%		93				10				11%
Other operating (income) and expenses, net	(4		)		(2		)		(2		)		100%		(1		)		(1		)		100%
Total operating expenses	521				501				20				4%		598				(97		)		(16)%
OPERATING INCOME	635				710				(75		)		(11)%		527				183				35%
OTHER EXPENSES (INCOME)
Interest expense, net	224				224				—				—%		211				13				6%
Allowance for equity funds used during construction	(33		)		(33		)		—				—%		(35		)		2				(6)%
Other (income) and expenses, net	3				4				(1		)		(25)%		8				(4		)		(50)%
Total other expenses (income)	194				195				(1		)		(1)%		184				11				6%
INCOME BEFORE INCOME TAXES	441				515				(74		)		(14)%		343				172				50%
INCOME TAX PROVISION	111				196				(85		)		(43)%		97				99				102%
NET INCOME	$	330			$	319			$	11			3%		$	246			$	73			30%

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Operating Revenues

Year ended December 31, 2018 compared to year ended December 31, 2017

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

																			Percentage
	2018							2017							Increase				Increase
(In millions)	Amount				Percentage			Amount				Percentage			(Decrease)				(Decrease)
Network revenues (a)	$	771			67	%		$	816			67	%		$	(45	)		(6	)%
Regional cost sharing revenues (a)	334				29	%		340				28	%		(6		)		(2	)%
Point-to-point	14				1	%		18				2	%		(4		)		(22	)%
Scheduling, control and dispatch (a)	15				1	%		14				1	%		1				7	%
Other	22				2	%		23				2	%		(1		)		(4	)%
Total	$	1,156			100	%		$	1,211			100	%		$	(55	)		(5	)%

____________________________

(a)	Includes a portion of the Formula Rate true-up of $(36) million and $(15) million for the year ended December 31, 2018 and 2017 , respectively.

Network revenues decreased primarily due to lower network revenue requirements at our Regulated Operating Subsidiaries. The main driver was the TCJA, which lowered the U.S. federal corporate income tax rate from 35% to 21%, reducing network revenues by $78 million . The reduction to the MISO adder for independent transmission ownership further reduced network revenues by $7 million . These decreases were partially offset by higher rate bases associated with higher balances of property, plant and equipment in-service in 2018 .

Regional cost sharing revenues decreased primarily due to lower regional revenue requirements at our Regulated Operating Subsidiaries. The main driver was the TCJA, which lowered the U.S. federal income tax rate from 35% to 21%, reducing regional cost sharing revenues by $27 million . The reduction to the MISO adder for independent transmission ownership further reduced regional cost sharing revenues by $2 million . These decreases were partially offset by an increase in capital projects placed in service that were eligible for regional cost sharing as well as higher accumulated investment for existing regional cost sharing projects in northern Michigan and Kansas for the year ended December 31, 2018 as compared to the same period in 2017 .

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

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

																			Percentage
	2017							2016							Increase				Increase
(In millions)	Amount				Percentage			Amount				Percentage			(Decrease)				(Decrease)
Network revenues (a)	$	816			67	%		$	814			72	%		$	2			—	%
Regional cost sharing revenues (a)	340				28	%		337				30	%		3				1	%
Point-to-point	18				2	%		20				2	%		(2		)		(10	)%
Scheduling, control and dispatch (a)	14				1	%		14				1	%		—				—	%
Other	24				2	%		20				2	%		4				20	%
Recognition of refund liabilities	(1		)		—	%		(80		)		(7	)%		79				(99	)%
Total	$	1,211			100	%		$	1,125			100	%		$	86			8	%

____________________________

(a)	Includes a portion of the Formula Rate true-up of $(15) million and $(17) million for the year ended December 31, 2017 and 2016 , respectively.

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

The recognition of the liability for the refund and estimated refund relating to the ROE complaints, described in Note 18 to the consolidated financial statements, resulted in a reduction of operating revenues during the year

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ended December 31, 2016 . We are not able to estimate whether any required refunds would be applied to all components of revenue listed in the table above or only certain components.

Operating revenues for the years ended December 31, 2017 and 2016 include revenue accruals and deferrals as described in Note 6 to the consolidated financial statements.

Operating Expenses

General and administrative expenses

Year ended December 31, 2018 compared to year ended December 31, 2017

General and administrative expenses increased due primarily to higher professional services such as legal and advisory services fees, which were related primarily to various development initiatives that were expenses at certain subsidiaries other than our Regulated Operating Subsidiaries and have not been included as components of revenue requirement at our Regulated Operating Subsidiaries.

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

General and administrative expenses decreased due to a reduction in professional services related to the Merger and a reduction in compensation-related expenses primarily due to lower bonuses and stock compensation expense, including the accelerated vesting of the share-based awards that occurred at the completion of the Merger in 2016 as described in Note 15 to the consolidated financial statements. The costs related to the Merger were recorded at ITC Holdings and have not been included as components of revenue requirement at our Regulated Operating Subsidiaries.

Depreciation and amortization expenses

Year ended December 31, 2018 compared to the respective period in 2017 and the year ended December 31, 2017 compared to the respective period in 2016

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, 2018 compared to the respective period in 2017 and the year ended December 31, 2017 compared to the respective period in 2016

Taxes other than income taxes increased due to higher property tax expenses primarily due to our Regulated Operating Subsidiaries’ 2017 and 2016 capital additions, which are included in the assessments for 2018 and 2017 property taxes, respectively.

Other Expenses (Income)

Interest Expense, Net

Year ended December 31, 2018 compared to year ended December 31, 2017

Interest expense, net remained consistent due to higher fixed debt balances and higher interest rates on revolving credit facility borrowings, offset by lower interest expense on short-term commercial paper borrowings, term loans and refinanced debt.

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

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

Income Tax Provision

Year ended December 31, 2018 compared to year ended December 31, 2017

Our effective tax rates for the years ended December 31, 2018 and 2017 are 25.2% and 38.1% , respectively. Our effective tax rate as of December 31, 2018 exceeded our 21% statutory federal income tax rate due primarily to state income taxes, partially offset by income tax relating to AFUDC equity. Our effective tax rate as of December 31, 2017 exceeded our 35% statutory federal income tax rate due primarily to the enactment of the TCJA and the

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required revaluation of our deferred tax assets and liabilities from 35% to 21%, partially offset by income taxes related to 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. See Note 11 to the consolidated financial statements for further discussion regarding our income tax provision.

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

Our effective tax rates for the years ended December 31, 2017 and 2016 are 38.1% and 28.3% , respectively. Our effective tax rate as of December 31, 2017 exceeded our 35% statutory federal income tax rate due primarily to the enactment of the TCJA and the required revaluation of our deferred tax assets and liabilities from 35% to 21%, partially offset by income tax relating to AFUDC equity. 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. 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 of funding our future capital requirements with cash from operations at our Regulated Operating Subsidiaries, our existing cash and cash equivalents, future issuances under our commercial paper program and amounts available under our revolving credit agreements (the terms of which are described in Note 10 to the consolidated financial statements). In addition, we may from time to time secure debt funding in the capital markets, although we can provide no assurance that we will be able to obtain financing on favorable terms or at all. As market conditions warrant, we may also from time to time repurchase debt securities issued by us, in the open market, in privately negotiated transactions, by tender offer or otherwise. We expect that our capital requirements will arise principally from our need to:

•	Fund capital expenditures at our Regulated Operating Subsidiaries. Our plans with regard to property, plant and equipment investments are described in detail above under “— Capital Investment and Operating Results Trends.”

•

Fund business development expenses and related capital expenditures. We are pursuing development activities for projects that will continue to result in the incurrence of development expenses and could result in significant capital expenditures incremental to our current plan. Refer to Note 18 to the consolidated financial statements for a discussion of contingent payments related to development projects.

•	Fund working capital requirements.

•	Fund our debt service requirements, including principal repayments and periodic interest payments, which are further described in detail below under “— Contractual Obligations.”

•	Fund any refund obligation in connection with the Second Complaint.

In addition to the expected capital requirements above, any adverse determinations or settlements relating to the regulatory matters or contingencies described in Notes 6 and 18 to the consolidated financial statements would result in additional capital requirements.

We believe that we have sufficient capital resources to meet our currently anticipated short-term needs. We rely on both internal and external sources of liquidity to provide working capital and fund capital investments. ITC Holdings’ sources of cash are dividends and other payments received by us from our Regulated Operating Subsidiaries and any of our other subsidiaries as well as the proceeds raised from the sale of our debt securities. Each of our Regulated Operating Subsidiaries, while wholly owned by ITC Holdings, is legally distinct from ITC Holdings and has no obligation, contingent or otherwise, to make funds available to us.

We expect to continue to utilize our commercial paper program and revolving credit agreements as well as our cash and cash equivalents as needed to meet our short-term cash requirements. As of December 31, 2018 , we had consolidated indebtedness under our revolving credit agreements of $208 million , with unused capacity under the revolving credit agreements of $692 million . Additionally, ITC Holdings had no commercial paper issued and outstanding as of December 31, 2018 , with the ability to issue $400 million under the commercial paper program. See Note 10 to the consolidated financial statements for a detailed discussion of the commercial paper program

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and our revolving credit agreements as well as the debt activity during the years ended December 31, 2018 and 2017 .

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 a recommendation to buy, sell or hold securities. Ratings are subject to revision or withdrawal at any time and each rating should be evaluated independently of any other rating. Our current credit ratings are displayed in the following table. An explanation of these ratings may be obtained from the respective rating agency.

		S&P (a)				Moody’s
		Rating		Outlook		Rating		Outlook
ITC Holdings
Senior Unsecured Notes		A-		Negative		Baa2		Stable
Commercial Paper		A-2		Negative		Prime-2		Stable
ITCTransmission
First Mortgage Bonds		A		Negative		A1		Stable
METC
Senior Secured Notes		A		Negative		A1		Stable
ITC Midwest
First Mortgage Bonds		A		Negative		A1		Stable
ITC Great Plains
First Mortgage Bonds		A		Negative		A1		Stable

____________________________

(a)	On March 21, 2018, S&P revised its outlook on all these entities from stable to negative, principally due to the risk of weakening credit metrics resulting from the TCJA as well as pending regulatory matters related to ROE at our MISO Regulated Operating Subsidiaries.

Covenants

Our debt instruments contain numerous financial and operating covenants that place significant restrictions on certain transactions, including the payment of dividends, as well as require us to meet certain financial ratios, which are described in Note 10 to the consolidated financial statements. As of December 31, 2018 , we were not in violation of any debt covenant. In the event of a downgrade in our credit ratings, none of the covenants would be directly impacted, although the borrowing costs under our revolving credit agreements may increase.

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Cash Flows

The following table summarizes cash flows for the periods indicated:

	Year Ended December 31,
(In millions)	2018				2017				2016
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	330			$	319			$	246
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	180				169				158
Recognition, refund and collection of revenue accruals and deferrals — including accrued interest	17				34				(2		)
Deferred income tax expense	107				195				219
Other	19				(110		)		68
Net cash provided by operating activities	653				607				689
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(769		)		(755		)		(750		)
Contributions in aid of construction	21				21				11
Other	1				(10		)		4
Net cash used in investing activities	(747		)		(744		)		(735		)
CASH FLOWS FROM FINANCING ACTIVITIES
Net issuance/repayment of debt (including commercial paper and revolving and term loan credit agreements)	238				511				161
Dividends on common and restricted stock	—				—				(90		)
Dividends to ITC Investment Holdings Inc.	(200		)		(300		)		(33		)
Refundable deposits from and repayments to generators for transmission network upgrades, net	3				(12		)		23
Settlement of share-based awards associated with the Merger — including cost of accelerated share-based awards	—				—				(137		)
Contribution from ITC Investment Holdings Inc. for the settlement of share-based awards associated with the Merger	—				—				137
Other	(5		)		(5		)		(19		)
Net cash provided by financing activities	36				194				42
NET (DECREASE) INCREASE IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH	(58		)		57				(4		)
CASH, CASH EQUIVALENTS AND RESTRICTED CASH — Beginning of period	68				11				15
CASH, CASH EQUIVALENTS AND RESTRICTED CASH — End of period	$	10			$	68			$	11

Cash Flows From Operating Activities

Year ended December 31, 2018 compared to year ended December 31, 2017

Net cash provided by operating activities increased in 2018 compared to 2017 . The increase in cash provided by operating activities was due primarily to the refund of $118 million , including interest, paid pursuant to the September 2016 Order during the year ended December 31, 2017. The increase was also driven by higher receipts from tax refunds received in 2018 of $12 million compared to the same period in 2017. This increase was partially offset by lower receipts from operating revenues in 2018 of $39 million primarily as a result of the TCJA, higher receipts in 2017 due to collection of $29 million related to the regional cost allocation refund paid in 2016 and higher interest payments of $19 million in 2018.

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

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

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cash receipts for the regional cost allocation refund in 2017 compared to cash payments in 2016, accelerated incentive payouts in 2016 associated with the Merger and lower income taxes paid during the year ended December 31, 2017 compared to the same period in 2016.

Cash Flows From Investing Activities

Year ended December 31, 2018 compared to the respective period in 2017 and the year ended December 31, 2017 compared to the respective period in 2016

Net cash used in investing activities during the years ended December 31, 2018 and December 31, 2017 was comparable to the years ended December 31, 2017 and December 31, 2016 , respectively.

Cash Flows From Financing Activities

Year ended December 31, 2018 compared to year ended December 31, 2017

Net cash provided by financing activities decreased in 2018 compared to 2017 . The decrease in cash provided by financing activities was due primarily to a decrease in long-term debt issuances and a decrease in borrowings under our term loan credit agreements. These decreases were partially offset by a decrease in retirement of long-term debt, a decrease in repayments under our term loan credit agreements, a decrease in net repayments under our commercial paper program and revolving credit agreements and a decrease in dividends paid to ITC Investment Holdings. See Note 10 to the consolidated financial statements for detail on the issuances and retirements of debt, repayment of our term loan credit agreement and a description of our revolving credit agreements and commercial paper program.

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

Net cash provided by financing activities increased in 2017 compared to 2016 . The increase in cash provided by financing activities was due primarily to a net increase in amounts outstanding under our term loan credit agreements compared to net repayments of term loan credit agreements in 2016 and an increase in long-term debt issuances. These increases were partially offset by net repayments of commercial paper under our commercial paper program and borrowing under our revolving credit agreements, an increase in payments to retire long-term debt, an increase in dividend payments and higher net repayments associated with refundable deposits for transmission network upgrades compared to net deposits in 2016. See Note 10 to the consolidated financial statements on the issuances and retirement of long-term debt.

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Contractual Obligations

The following table details our contractual obligations as of December 31, 2018 :

					Due within				Due in				Due in				Due after
(In millions)	Total				1 Year				Years 2-3				Years 4-5				5 years
Debt:
ITC Holdings Senior Notes	$	2,750			$	—			$	200			$	750			$	1,800
ITC Holdings revolving credit agreement	37				—				—				37				—
ITCTransmission First Mortgage Bonds	710				—				—								710
ITCTransmission revolving credit agreement	27				—				—				27				—
METC Senior Secured Notes (a)	475				—				—				—				475
METC revolving credit agreement	70				—				—				70				—
ITC Midwest First Mortgage Bonds	1,085				—				35				—				1,050
ITC Midwest revolving credit agreement	34				—				—				34				—
ITC Great Plains First Mortgage Bonds	150				—				—				—				150
ITC Great Plains revolving credit agreement	40				—				—				40				—
Interest payments:
ITC Holdings Senior Notes	1,051				108				194				173				576
ITCTransmission First Mortgage Bonds	847				33				65				65				684
METC Senior Secured Notes (a)	508				20				40				40				408
ITC Midwest First Mortgage Bonds	1,155				49				95				93				918
ITC Great Plains First Mortgage Bonds	162				6				12				12				132
Operating leases	4				1				2				1				—
Purchase obligations	49				48				1				—				—
Regulatory liabilities — revenue deferrals, including accrued interest	76				27				49				—				—
METC Easement Agreement	319				10				20				20				269
Total obligations	$	9,549			$	302			$	713			$	1,362			$	7,172

____________________________

(a)	On January 15, 2019, METC issued $50 million of 4.55% Senior Secured Notes, due January 15, 2049. METC has an additional $50 million delayed draw of 30-year Senior Secured Notes in July 2019 at 4.65% . Refer to Note 10 to the consolidated financial statements for further details on the issuance. These commitments are not included in the table above.

Interest payments included above relate only to our fixed-rate long-term debt outstanding at December 31, 2018 . 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 2018 , we paid $8 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, 2018 , 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 18 to the consolidated financial statements for more information on our operating leases and purchase 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 6 to the consolidated financial statements. These amounts will offset future revenue requirement for purposes of calculating our Formula Rates as part of the true-up mechanism in our rate construct.

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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 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, income taxes refundable related to implementation of the TCJA and liabilities to refund deposits from generators for transmission network upgrades, which are recorded in other current and long term liabilities, are not known with certainty. As a result, cash obligations for these items are excluded from the contractual obligations table above.

Critical Accounting Policies and Estimates

Our consolidated financial statements are prepared in accordance with GAAP. The preparation of these consolidated financial statements requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. The application of these policies requires judgments regarding future events.

These estimates and judgments, in and of themselves, could materially impact the consolidated financial statements and disclosures based on varying assumptions, as future events rarely develop exactly as forecasted, and even the best estimates routinely require adjustment.

The following is a list of accounting policies that are most significant to the portrayal of our financial condition and results of operations and/or that require management’s most difficult, subjective or complex judgments.

Regulation

Our Regulated Operating Subsidiaries are subject to rate regulation by the FERC. As a result, we apply accounting principles in accordance with the standards set forth by the FASB for accounting for the effects of certain types of regulation. Use of this accounting guidance results in differences in the application of GAAP between regulated and non-regulated businesses and requires the recording of regulatory assets and liabilities for certain transactions that would have been treated as expense or revenue in non-regulated businesses. As described in Note 7 to the consolidated financial statements, we had regulatory assets and liabilities of $212 million and $818 million , respectively, as of December 31, 2018 . 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 aggregate losses of $36 million relating to intangible assets at METC and ITC Great Plains at December 31, 2018 that are described in Note 9 to the consolidated financial statements.

We believe that current available facts support the continued applicability of the standards for accounting for the effects of certain types of regulation and that all regulatory assets and liabilities are recoverable or refundable under our current rate environment.

Revenue Recognition under Cost-Based Formula Rates with True-Up Mechanism

Our Regulated Operating Subsidiaries recover expenses and earn a return on and recover investments in property, plant and equipment on a current basis , under their forward-looking cost-based Formula Rates with a true-up mechanism.

Under their Formula Rates, our Regulated Operating Subsidiaries use forecasted expenses, property, plant and equipment, point-to-point revenues and other items for the upcoming calendar year to establish their projected revenue requirement and for the MISO Regulated Operating Subsidiaries, their component of the billed network rates for service on their systems from January 1 to December 31 of that year. The cost-based Formula Rates include a true-up mechanism, whereby our Regulated Operating Subsidiaries compare their actual revenue requirements to their billed revenues for each year in order to subsequently collect or refund any over-recovery or

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under-recovery of revenues, as appropriate. The over- or under-collection typically results from differences between the projected revenue requirement used as the basis for billing and actual revenue requirement at each of our Regulated Operating Subsidiaries, or from differences between actual and projected monthly peak loads at our MISO Regulated Operating Subsidiaries.

The true-up mechanisms under our Formula Rates meet the GAAP requirements for accounting for rate-regulated utilities and the effects of certain alternative revenue programs. Accordingly, revenue is recognized during each reporting period based on actual revenue requirements calculated using the cost-based Formula Rates. Our Regulated Operating Subsidiaries accrue or defer revenues to the extent that their actual revenue requirement for the reporting period is higher or lower, respectively, than the amounts billed relating to that reporting period. The true-up amount is automatically reflected in customer bills within two years under the provisions of the Formula Rates. See Note 7 to the consolidated financial statements for the regulatory assets and liabilities recorded at our Regulated Operating Subsidiaries’ as a result of the Formula Rate revenue accruals and deferrals.

Valuation of Goodwill

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

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

As of December 31, 2018 and 2017 , consolidated goodwill totaled $950 million . We completed our annual goodwill impairment test for our reporting units as of October 1, 2018 using a qualitative assessment and determined that no impairment exists. There were no events subsequent to October 1, 2018 that indicated impairment of our goodwill. We do not believe there is a material risk of our goodwill being impaired in the near term for any of our reporting units.

Contingent Obligations

We are subject to a number of federal and state laws and regulations, as well as other factors and conditions that potentially subject us to environmental, litigation, income tax and other contingencies. Additionally, we have other contingent obligations that may be required to be paid to developers based on achieving certain milestones relating to development initiatives. We periodically evaluate our exposure to such contingencies and record liabilities for those matters where a loss is considered probable and reasonably estimable. Our liabilities exclude any estimates for legal costs not yet incurred associated with handling these matters, which could be material. The adequacy of liabilities recorded can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect our consolidated financial statements. These events or conditions include, without limitation, the following:

•	Changes in existing state or federal regulation by governmental authorities having jurisdiction over air quality, water quality, control of toxic substances, hazardous and solid wastes and other environmental matters.

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•	Changes in existing federal income tax laws or IRS regulations.

•	Identification and evaluation of lawsuits or complaints in which we may be or have been named as a defendant.

•	Resolution or progression of existing matters through the legislative process, the courts, the FERC, the NERC, the IRS or the Environmental Protection Agency.

•	Completion of certain milestones relating to development initiatives.

Refer to Note 18 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 12 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 2 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, excluding revolving credit agreements was $5,186 million at December 31, 2018 . The total book value of our consolidated long-term debt, excluding revolving credit agreements was $5,130 million at December 31, 2018 . We performed an analysis calculating the impact of changes in interest rates on the fair value of long-term debt, excluding revolving credit agreements, at December 31, 2018 . An increase in interest rates of 10% (from 5.0% to 5.5%, for example) at December 31, 2018 would decrease the fair value of debt by $224 million , and a decrease in interest rates of 10% at December 31, 2018 would increase the fair value of debt by $243 million at that date.

Revolving Credit Agreements

At December 31, 2018 , we had a consolidated total of $208 million outstanding under our revolving credit agreements, which are variable rate loans and fair value approximates book value. A 10% increase or decrease

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in borrowing rates under the revolving credit agreements compared to the weighted average rates in effect at December 31, 2018 would increase or decrease interest expense by less than $1 million for an annual period with a constant borrowing level of $208 million .

Commercial Paper

ITC Holdings has an ongoing commercial paper program for the issuance and sale of unsecured commercial paper. At December 31, 2018 , ITC Holdings did not have any commercial paper issued or outstanding.

Derivative Instruments and Hedging Activities

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

In November 2017, we terminated $375 million of 10-year interest rate swap contracts and $375 million of 5-year interest rate swap contracts that managed the interest rate risk associated with the unsecured notes issued by ITC Holdings described in Note 10 to the consolidated financial statements. At December 31, 2018 , ITC Holdings did not have any interest rate swaps outstanding.

Credit Risk

Our credit risk is primarily with DTE Electric, Consumers Energy and IP&L, which were responsible for approximately 21.4% , 23.1% and 26.6% , respectively, or $248 million , $269 million and $309 million , respectively, of our consolidated billed revenues for the year ended December 31, 2018 . These percentages and amounts of total billed revenues of DTE Electric, Consumers Energy and IP&L include the collection of 2016 revenue accruals and deferrals and exclude any amounts for the 2018 revenue accruals and deferrals that were included in our 2018 operating revenues but will not be billed to our customers until 2020 . Refer to “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cost-Based Formula Rates with True-Up Mechanism” for a discussion on the difference between billed revenues and operating revenues. Under DTE Electric’s and Consumers Energy’s current rate structure, DTE Electric and Consumers Energy include in their retail rates the actual cost of transmission services provided by ITCTransmission and METC, respectively, in their billings to their customers, effectively passing through to end-use consumers the total cost of transmission service. IP&L currently includes in their retail rates an allowance for transmission services provided by ITC Midwest in their billings to their customers. However, any financial difficulties experienced by DTE Electric, Consumers Energy or IP&L may affect their ability to make payments for transmission service to ITCTransmission, METC, and ITC Midwest, which could negatively impact our business. MISO, as our MISO Regulated Operating Subsidiaries’ billing agent, bills DTE Electric, Consumers Energy, IP&L and other customers on a monthly basis and collects fees for the use of the MISO Regulated Operating Subsidiaries’ transmission systems. SPP is the billing agent for ITC Great Plains and bills transmission customers for the use of ITC Great Plains transmission systems. MISO and SPP have implemented strict credit policies for its members’ customers, which include customers using our transmission systems. Specifically, MISO and SPP require a letter of credit or cash deposit equal to the credit exposure, which is determined by a credit scoring model and other factors, from any customer using a member’s transmission system.

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ITEM 8.      FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

The following financial statements and schedules are included herein:

		Page
Management’s Report on Internal Control over Financial Reporting		45
Report of Independent Registered Public Accounting Firm		46
Consolidated Statements of Financial Position as of December 31, 2018 and 2017		47
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2018, 2017 and 2016		48
Consolidated Statements of Changes in Stockholder’s Equity for the Years Ended December 31, 2018, 2017 and 2016		49
Consolidated Statements of Cash Flows for the Years Ended December 31, 2018, 2017 and 2016		50
Notes to Consolidated Financial Statements		51
Schedule I — Condensed Financial Information of Registrant		133

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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, 2018 .

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of

ITC Holdings Corp.

Novi, Michigan

Opinion on the Financial Statements

We have audited the accompanying consolidated statements of financial position of ITC Holdings Corp. and subsidiaries (the "Company") as of December 31, 2018 and 2017 , the related consolidated statements of comprehensive income, changes in stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2018 , and the related notes and the schedule listed in the Index at Item 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material aspects, the financial position of the Company as of December 31, 2018 and 2017 , and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018 , in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ DELOITTE & TOUCHE LLP

Detroit, Michigan

February 14, 2019

We have served as the Company’s auditor since 2001.

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ITC HOLDINGS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

	December 31,
(In millions, except share data)	2018				2017
ASSETS
Current assets
Cash and cash equivalents	$	6			$	66
Accounts receivable	102				119
Inventory	32				29
Regulatory assets	12				18
Income tax receivable	1				15
Prepaid and other current assets	11				13
Total current assets	164				260
Property, plant and equipment (net of accumulated depreciation and amortization of $1,779 and $1,675, respectively)	7,910				7,309
Other assets
Goodwill	950				950
Intangible assets (net of accumulated amortization of $39 and $35, respectively)	38				41
Regulatory assets	200				197
Other	67				66
Total other assets	1,255				1,254
TOTAL ASSETS	$	9,329			$	8,823
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities
Accounts payable	$	106			$	97
Accrued compensation	30				28
Accrued interest	50				60
Accrued taxes	64				57
Regulatory liabilities	178				183
Refundable deposits and advances for construction	33				25
Debt maturing within one year	—				100
Other	11				12
Total current liabilities	472				562
Accrued pension and postretirement liabilities	68				74
Deferred income taxes	721				601
Regulatory liabilities	640				619
Refundable deposits	13				29
Other	26				17
Long-term debt	5,338				5,001
Commitments and contingent liabilities (Notes 6 and 18)
STOCKHOLDER’S EQUITY
Common stock, without par value, 235,000,000 shares authorized as of December 31, 2018, and 224,203,112 shares issued and outstanding at December 31, 2018 and 2017	892				892
Retained earnings	1,155				1,026
Accumulated other comprehensive income	4				2
Total stockholder’s equity	2,051				1,920
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	9,329			$	8,823

See notes to consolidated financial statements.

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ITC HOLDINGS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Year Ended December 31,
(In millions)	2018				2017				2016
OPERATING REVENUES
Transmission and other services	$	1,192			$	1,226			$	1,142
Formula Rate true-up	(36		)		(15		)		(17		)
Total operating revenue	1,156				1,211				1,125
OPERATING EXPENSES
Operation and maintenance	109				110				114
General and administrative	127				121				234
Depreciation and amortization	180				169				158
Taxes other than income taxes	109				103				93
Other operating (income) and expense, net	(4		)		(2		)		(1		)
Total operating expenses	521				501				598
OPERATING INCOME	635				710				527
OTHER EXPENSES (INCOME)
Interest expense, net	224				224				211
Allowance for equity funds used during construction	(33		)		(33		)		(35		)
Other (income) and expenses, net	3				4				8
Total other expenses (income)	194				195				184
INCOME BEFORE INCOME TAXES	441				515				343
INCOME TAX PROVISION	111				196				97
NET INCOME	330				319				246
OTHER COMPREHENSIVE INCOME (LOSS)
Derivative instruments, net of tax (Note 14)	1				—				(2		)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX (NOTE 14)	1				—				(2		)
TOTAL COMPREHENSIVE INCOME	$	331			$	319			$	244

See notes to consolidated financial statements.

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ITC HOLDINGS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN

STOCKHOLDER’S EQUITY

									Accumulated
									Other				Total
					Retained				Comprehensive				Stockholder’s
	Common Stock				Earnings				Income (Loss)				Equity
(In millions)
BALANCE, DECEMBER 31, 2015	$	829			$	876			$	4			$	1,709
Net income	—				246				—				246
Repurchase and retirement of common stock	(9		)		—				—				(9		)
Dividends declared on common stock	—				(90		)		—				(90		)
Dividends to ITC Investment Holdings Inc.	—				(33		)		—				(33		)
Stock option exercises	11				—				—				11
Share-based compensation, net of forfeitures	18				—				—				18
Share-based compensation associated with the Merger (Note 15)	41				—				—				41
Settlement of share-based awards associated with the Merger (Note 17)	(137		)		(1		)		—				(138		)
Contribution from ITC Investment Holdings Inc. for the settlement of share-based awards associated with the Merger (Note 17)	137				—				—				137
Tax benefit for excess tax deductions of share-based compensation	—				9				—				9
Other comprehensive (loss), net of tax (Note 14)	—				—				(2		)		(2		)
Other	2				—				—				2
BALANCE, DECEMBER 31, 2016	$	892			$	1,007			$	2			$	1,901
Net income	—				319				—				319
Dividends to ITC Investment Holdings Inc.	—				(300		)		—				(300		)
BALANCE, DECEMBER 31, 2017	$	892			$	1,026			$	2			$	1,920
Opening balance reclassification (Note 2)	—				(1		)		1				—
Net income	—				330				—				330
Dividends to ITC Investment Holdings Inc.	—				(200		)		—				(200		)
Other comprehensive income, net of tax (Note 14)	—				—				1				1
BALANCE, DECEMBER 31, 2018	$	892			$	1,155			$	4			$	2,051

See notes to consolidated financial statements.

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ITC HOLDINGS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
(In millions)	2018				2017				2016
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	330			$	319			$	246
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	180				169				158
Recognition, refund and collection of revenue accruals and deferrals — including accrued interest	17				34				(2		)
Deferred income tax expense	107				195				219
Allowance for equity funds used during construction	(33		)		(33		)		(35		)
Expense for the accelerated vesting of share-based awards associated with the Merger	—				—				41
Other	10				11				30
Changes in assets and liabilities, exclusive of changes shown separately:
Accounts receivable	17				(17		)		(2		)
Income tax receivable	14				—				(17		)
Accounts payable	6				(3		)		5
Accrued interest	(10		)		7				1
Accrued taxes	7				5				4
Net estimated refund related to return on equity complaints	6				(113		)		90
Other current and non-current assets and liabilities, net	2				33				(49		)
Net cash provided by operating activities	653				607				689
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(769		)		(755		)		(750		)
Contributions in aid of construction	21				21				11
Other	1				(10		)		4
Net cash used in investing activities	(747		)		(744		)		(735		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt, net of discount	400				1,199				599
Borrowings under revolving credit agreements	832				1,065				1,042
Borrowings under term loan credit agreements	—				250				—
Net (repayment) issuance of commercial paper, net of discount	—				(148		)		48
Retirement of long-term debt — including extinguishment of debt costs	(100		)		(477		)		(139		)
Repayments of revolving credit agreements	(844		)		(1,178		)		(1,028		)
Repayments of term loan credit agreements	(50		)		(200		)		(361		)
Dividends on common and restricted stock	—				—				(90		)
Dividends to ITC Investment Holdings Inc.	(200		)		(300		)		(33		)
Refundable deposits from generators for transmission network upgrades	6				16				33
Repayment of refundable deposits from generators for transmission network upgrades	(3		)		(28		)		(10		)
Settlement of share-based awards associated with the Merger — including cost of accelerated share-based awards	—				—				(137		)
Contribution from ITC Investment Holdings Inc. for the settlement of share-based awards associated with the Merger	—				—				137
Other	(5		)		(5		)		(19		)
Net cash provided by financing activities	36				194				42
NET (DECREASE) INCREASE IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH	(58		)		57				(4		)
CASH, CASH EQUIVALENTS AND RESTRICTED CASH — Beginning of period	68				11				15
CASH, CASH EQUIVALENTS AND RESTRICTED CASH — End of period	$	10			$	68			$	11

See notes to consolidated financial statements.

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ITC HOLDINGS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1 .     GENERAL

ITC Holdings and its subsidiaries are engaged in the transmission of electricity in the United States. Through our Regulated Operating Subsidiaries, we own and operate high-voltage systems in Michigan’s Lower Peninsula and portions of Iowa, Minnesota, Illinois, Missouri, Kansas, and Oklahoma that transmit electricity from generating stations to local distribution facilities connected to our systems. Our business strategy is to own, operate, maintain and invest in transmission infrastructure in order to enhance system integrity and reliability, reduce transmission constraints and support new generating resources to interconnect to our transmission systems. We also are pursuing transmission development projects not within our existing systems, which are also intended to improve overall grid reliability, reduce transmission constraints and facilitate interconnections of new generating resources, as well as enhance competitive wholesale electricity markets.

Our Regulated Operating Subsidiaries are independent electric transmission utilities, with rates regulated by the FERC and established on a cost-of-service model. ITCTransmission’s service area is located in southeastern Michigan, while METC’s service area covers approximately two-thirds of Michigan’s Lower Peninsula and is contiguous with ITCTransmission’s service area. ITC Midwest’s service area is located in portions of Iowa, Minnesota, Illinois and Missouri and ITC Great Plains currently owns assets located in Kansas and Oklahoma. MISO bills and collects revenues from the MISO Regulated Operating Subsidiaries’ customers. SPP bills and collects revenue from ITC Great Plains customers. ITC Interconnection currently owns assets in Michigan and earns revenues based on its facilities reimbursement agreement with a merchant generating company.

The Merger

On February 9, 2016, ITC Holdings entered into the Merger Agreement with Fortis, FortisUS and Merger Sub. On April 20, 2016, Fortis reached a definitive agreement with GIC for GIC to acquire an indirect 19.9% equity interest in ITC Holdings upon completion of the Merger. On October 14, 2016 , ITC Holdings and Fortis completed the Merger contemplated by the Merger Agreement. On the same date, the common shares of ITC Holdings were delisted from the NYSE. Due to the delisting of ITC Holdings common shares, there is limited share data, and no per share data, presented in this Form 10-K.

For the year ended December 31, 2017, we expensed approximately $5 million related to the Merger for internal labor and associated costs. For the year ended December 31, 2016, expenses related to the Merger for internal labor and associated costs were approximately $58 million and external legal, advisory and financial services fees were approximately $55 million . For the year ended December 31, 2016, the internal labor and associated costs included approximately $41 million of expense that was recognized due to the accelerated vesting of the share-based awards described in Note 15 . The majority of these Merger-related costs were recorded within general and administrative expenses. The external and internal costs related to the Merger were recorded at ITC Holdings and have not been included as components of revenue requirement at our Regulated Operating Subsidiaries.

2 .      RECENT ACCOUNTING PRONOUNCEMENTS

Recently Adopted Pronouncements

Revenue from Contracts with Customers

In May 2014, the FASB issued authoritative guidance requiring entities to apply a new model for recognizing revenue from contracts with customers. Subsequent updates have been issued primarily to provide implementation guidance related to the initial guidance issued in May 2014. The guidance 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 guidance may be adopted using either (a) a full retrospective method, whereby comparative periods would be restated to present the impact of the new standard, with the cumulative effect of applying the standard recognized as of the earliest period presented, or (b) a modified retrospective method, under which comparative periods would not be restated and the cumulative effect of applying the standard would be recognized at the date of initial adoption. We adopted the guidance effective January 1, 2018 using the modified retrospective approach; however, we did not identify or record any adjustments to the opening balance of retained earnings upon adoption.

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Substantially all of our revenue from contracts with customers is generated from providing transmission services to customers based on tariff rates, as approved by the FERC, and is in the scope of the new guidance. The true-up mechanisms under our Formula Rates are considered alternative revenue programs of rate-regulated utilities and are outside the scope of the new guidance, as they are not considered to be contracts with customers. The implementation of the new standard did not have a material impact on the amount and timing of revenue recognition. However, the following summarizes the impacts of the adoption of this new accounting guidance on our financial statements:

•

Our consolidated statements of comprehensive income have been modified to present operating revenues arising from alternative revenue programs (Formula Rate true-up) separately from revenues in the scope of the new guidance (Transmission and other services). In connection with this presentation change, we adopted an accounting policy whereby only the initial origination of our alternative revenue program revenue is reported in the Formula Rate true-up line on our consolidated statements of comprehensive income . When those amounts are subsequently included in the price of utility service and billed or refunded to customers, we account for that event as the recovery or settlement of the associated regulatory asset or regulatory liability, respectively.

•	Note 4 has been added to address the requirement to provide more information regarding the nature, amount, timing, and uncertainty of revenue and cash flows.

•	Note 5 has been added to provide more information about changes in accounts receivable from customers.

Recognition and Measurement of Financial Instruments

In January 2016, the FASB issued authoritative guidance amending the classification and measurement of financial instruments. The guidance requires entities to carry most investments in equity securities at fair value and recognize changes in fair value in net income, unless the investment results in consolidation or equity method accounting. Additionally, the new guidance amends certain disclosure requirements associated with the fair value of financial instruments. The guidance is required to be adopted using a modified retrospective approach, with limited exceptions. The guidance impacts the accounting for certain of our investments previously accounted for as available-for-sale with changes in fair value recorded in other comprehensive income; upon adoption of the guidance on January 1, 2018, we began accounting for such investments with changes in fair value reported in net income. We recorded an immaterial adjustment to retained earnings in accordance with the modified retrospective adoption requirement.

Presentation of Restricted Cash in the Statement of Cash Flows

In November 2016, the FASB issued authoritative guidance on the presentation of restricted cash and restricted cash equivalents within the statement of cash flows. The new guidance specifies that restricted cash and restricted cash equivalents shall be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. The guidance does not, however, provide a definition of restricted cash or restricted cash equivalents. We adopted the guidance effective for interim and annual periods beginning on January 1, 2018, using a retrospective approach as required.

Restricted cash includes cash and cash equivalents that are legally or contractually restricted for use or withdrawal or are formally set aside for a specific purpose. See reconciliation of cash, cash equivalents and restricted cash in Note 19 .

The following summarizes the impact of this adoption on our previously reported amounts:

	Twelve months ended December 31,
	2017				2016				2015
Restricted cash - Beginning balance	$	3			$	1			$	2
Restricted cash - Ending balance	2				3				1
Change - Other current and non-current assets and liabilities, net within consolidated statements of cash flows	$	(1	)		$	2			$	(1	)

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

In March 2017, the FASB issued authoritative guidance that requires entities to disaggregate the current service cost component of net benefit cost (i.e., net periodic pension cost and net periodic postretirement benefit cost) and present it in the same consolidated statements of comprehensive income line item as other current

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compensation costs for employees (i.e., within General and administrative for us). Entities are required to present the other components of net benefit cost (“non-service costs”) elsewhere in the consolidated statements of comprehensive income and outside operating income. The line or lines containing such other components must be appropriately described on the face of the consolidated statements of comprehensive income; otherwise, disclosure of the location of such other costs in the consolidated statements of comprehensive income is required. We elected to present the non-service costs within the line “Other (income) and expenses, net” in the consolidated statements of comprehensive income and include disclosure within Note 12 . In addition, the new guidance allows capitalization of only the service cost component of net benefit cost.

We adopted the guidance effective January 1, 2018. The changes regarding cost capitalization were applied prospectively while the changes to the presentation of net benefit cost in the consolidated statements of comprehensive income were adopted retrospectively. We applied the practical expedient that permits entities to use amounts previously disclosed in the pension and postretirement welfare footnotes as the estimation basis for the retrospective adjustments to the consolidated statements of comprehensive income . The following summarizes the impact of this adoption on our previously reported amounts:

	Year Ended December 31,
(in millions)	2017				2016
General and administrative
Reported	$	123			$	239
Adjustment	(2		)		(5		)
Adjusted	$	121			$	234
Other (income) and expenses, net
Reported	$	2			$	3
Adjustment	2				5
Adjusted	$	4			$	8

Reclassification of Certain Tax Effects from AOCI

In February 2018, the FASB issued authoritative guidance that permits entities to reclassify the stranded tax effects resulting from the TCJA from AOCI to retained earnings. The stranded tax effects were the result of the revaluation of deferred taxes through net income as a result of the tax rate change, with no adjustment to the tax effects recorded in AOCI. The guidance is effective for fiscal years beginning January 1, 2019; however, we have elected to early adopt the guidance as of January 1, 2018. We elected to apply the guidance in the period of adoption, accounted for as a change in accounting principle resulting from the adoption of new accounting guidance. We recorded a $1 million adjustment to AOCI and retained earnings upon adoption. We apply an investment by investment approach to releasing income tax effects from AOCI.

Recently Issued Pronouncements

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

Accounting for Leases

In February 2016, the FASB issued authoritative guidance on accounting for leases, which primarily impacts accounting by lessees. This guidance created a dual approach for lessee accounting, with lease classification determined in accordance with principles in previous lease guidance. Consolidated statements of comprehensive income 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 previous accounting guidance, operating leases were not recorded on the balance sheet of lessees. In January 2018, additional guidance was issued that provides an optional transition practical expedient that allows existing or expired easements that were not previously accounted for as leases under current guidance to not be evaluated under the new guidance.

The new guidance was effective on January 1, 2019. Early adoption was permitted; however, we did not early adopt. In July 2018, transition relief guidance was issued whereby entities may elect to apply the new guidance on a modified retrospective basis at the adoption date (i.e., January 1, 2019) as opposed to at the beginning of the earliest period presented in the financial statements (i.e., January 1, 2017). We elected this transition relief

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and began applying the new guidance as of January 1, 2019; however, prior period comparative financial statements and disclosures will continue to be presented under previous lease accounting guidance.

In connection with our adoption of the new guidance, we elected various practical expedients and made certain accounting policy elections, including:

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

◦	whether any expired or existing contracts are or contain leases,

◦	the lease classification of any expired or existing leases, and

◦	the initial direct costs for any existing leases;

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

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

Based on our assessment to date, leasing activities primarily relate to office facilities. Adoption of the guidance will result in recognition of additional lease assets and lease liabilities of less than $5 million. We do not expect the new guidance to materially affect our results of operations or cash flows.

Targeted Improvements to Accounting for Hedging Activities

In August 2017, the FASB issued authoritative guidance to make targeted improvements to hedge accounting to better align with an entity’s risk management objectives and to reduce the complexity of hedge accounting. Among other changes, the new guidance simplifies hedge accounting by (a) allowing more time for entities to complete initial quantitative hedge effectiveness assessments, (b) enabling entities to elect to perform subsequent effectiveness assessments qualitatively, (c) eliminating the concept of recognizing periodic hedge ineffectiveness for cash flow hedges, (d) requiring the change in fair value of a derivative to be recorded in the same consolidated statements of comprehensive income line item as the earnings effect of the hedged item, and (e) permitting additional hedge strategies to qualify for hedge accounting. In addition, the guidance modifies existing disclosure requirements and adds new disclosure requirements, including tabular disclosures about both (a) the total amounts reported in the consolidated statements of comprehensive income for each income and expense line item that is affected by hedging and (b) the effects of hedging on those line items. The guidance is effective as of January 1, 2019, including interim periods within those fiscal years, with early adoption permitted. We did not early adopt. The guidance is required to be adopted on a modified retrospective basis to existing hedging relationships and on a prospective basis for the presentation and disclosure requirements. We do not expect a significant impact upon adoption, but we will add the required disclosures, as applicable.

Fair Value Measurement Disclosures

In August 2018, the FASB issued authoritative guidance modifying the disclosure requirements for fair value measurements. The new guidance adds disclosure requirements for Level 3 fair value measurements and modifies disclosure requirements for public entities regarding certain fair value measurements. In addition, the guidance eliminates (a) the disclosure of the amount of, and reasons for, transfers between Level 1 and Level 2 assets and liabilities, (b) the policy for timing of transfers between levels of the fair value hierarchy, and (c) other disclosure requirements related to Level 3 fair value measurements. The new guidance is effective for fiscal years beginning after December 15, 2019, including interim periods therein. Early adoption is permitted. The guidance is required to be adopted primarily on a retrospective basis, with certain new and modified disclosures requiring prospective application. We are still evaluating the new guidance, but do not expect our disclosures to be significantly impacted upon adoption, particularly given we do not currently have any Level 3 fair value measurements.

Pension and Other Postretirement Plan Disclosures

In August 2018, the FASB issued authoritative guidance modifying the disclosure requirements for defined benefit pension and other postretirement plans. The new guidance requires disclosures including (a) the weighted average interest credit rates used for cash balance pension plans, (b) a narrative description of the reasons for significant gains and losses affecting the benefit obligation for the period, and (c) an explanation of other significant changes in the benefit obligation or plan assets. In addition, the guidance removes currently required disclosures including, among others, the requirement for public entities to disclose the effects of a one-percentage-point change

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on the assumed health care costs and the effect of the change in rates on service cost, interest cost, and the benefit obligation for postretirement health care benefits. The new guidance, which is effective for fiscal years ending after December 15, 2020 with early adoption permitted, is required to be adopted on a retrospective basis. We are still evaluating the impact of the new guidance on our disclosures.

Accounting for Cloud Computing Arrangements

In August 2018, the FASB issued authoritative guidance to address the accounting for implementation costs incurred in a cloud computing agreement that is a service contract. The new standard aligns the accounting for implementation costs incurred in a cloud computing arrangement as a service contract with existing guidance on capitalizing costs associated with developing or obtaining internal-use software. In addition, the new guidance requires entities to expense capitalized implementation costs of a cloud computing arrangement that is a service contract over the term of the agreement and to present the expense in the same income statement line item as the hosting fees. The guidance is effective for fiscal years beginning after December 15, 2019 with early adoption permitted. We are still evaluating the impact of the new standard on our financial statements, including disclosures.

3 .     SIGNIFICANT ACCOUNTING POLICIES

A summary of the major accounting policies followed in the preparation of the accompanying consolidated financial statements, which conform to GAAP, is presented below:

Principles of Consolidation — ITC Holdings consolidates its majority owned subsidiaries. We eliminate all intercompany balances and transactions.

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

Regulation — Our Regulated Operating Subsidiaries are subject to the regulatory jurisdiction of the FERC, which issues orders pertaining to rates, recovery of certain costs, including the costs of transmission assets and regulatory assets, conditions of service, accounting, financing authorization and operating-related matters. The utility operations of our Regulated Operating Subsidiaries meet the accounting standards set forth by the FASB for the accounting effects of certain types of regulation. These accounting standards recognize the cost based rate setting process, which results in differences in the application of GAAP between regulated and non-regulated businesses. These standards require the recording of regulatory assets and liabilities for certain transactions that would have been recorded as revenue and expense in non-regulated businesses. Regulatory assets represent costs that will be included as a component of future tariff rates and regulatory liabilities represent amounts provided in the current tariff rates that are intended to recover costs expected to be incurred in the future or amounts to be refunded to customers.

Cash and Cash Equivalents — We consider all unrestricted highly-liquid temporary investments with an original maturity of three months or less at the date of purchase to be cash equivalents.

Restricted Cash and Restricted Cash Equivalents - Restricted cash and restricted cash equivalents include cash and cash equivalents that are legally or contractually restricted for use or withdrawal or are formally set aside for a specific purpose.

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

Inventories — Materials and supplies inventories are valued at average cost. Additionally, the costs of warehousing activities are recorded here and included in the cost of materials when requisitioned.

Property, Plant and Equipment — Depreciation and amortization expense on property, plant and equipment was $170 million , $160 million and $149 million for 2018 , 2017 and 2016 , 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

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depreciation rate for our Regulated Operating Subsidiaries included in our consolidated statements of comprehensive income was 2.0% for 2018 , 2017 and 2016 . The composite depreciation rates include depreciation primarily on transmission station equipment, towers, poles and overhead and underground lines that have a useful life ranging from 45 to 60 years . The portion of depreciation expense related to asset removal costs is added to regulatory liabilities or deducted from regulatory assets and removal costs incurred are deducted from regulatory liabilities or added to regulatory assets. Certain of our Regulated Operating Subsidiaries capitalize to property, plant and equipment AFUDC in accordance with the FERC regulations. AFUDC represents the composite cost incurred to fund the construction of assets, including interest expense and a return on equity capital devoted to construction of assets. The interest component of AFUDC of $9 million was a reduction to interest expense for 2018 , 2017 and 2016 .

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

Property, plant and equipment includes capital equipment inventory stated at original cost consisting of items that are expected to be used exclusively for capital projects.

Property, plant and equipment at ITC Holdings and non-regulated subsidiaries is stated at its acquired cost. Proceeds from salvage less the net book value of the disposed assets is recognized as a gain or loss on disposal. Depreciation is computed based on the acquired cost less expected residual value and is recognized over the estimated useful lives of the assets on a straight-line method for financial reporting purposes and accelerated methods for income tax reporting purposes.

Generator Interconnection Projects and Contributions in Aid of Construction — Certain capital investment at our Regulated Operating Subsidiaries relates to investments made under generator interconnection agreements. The generator interconnection agreements typically consist of both transmission network upgrades, which are a category of upgrades deemed by the FERC to benefit the transmission system as a whole, as well as direct connection facilities, which are necessary to interconnect the generating facility to the transmission system and primarily benefit the generating facility. As a result, generator interconnection agreements may require the generator to make a contribution in aid of construction to our Regulatory Operating Subsidiaries to cover the cost of certain investments made by us as part of the agreement .

Our investments in transmission facilities are recorded to property, plant and equipment, and are recorded net of any contribution in aid of construction. We may also receive refundable deposits from the generator for certain investment in network upgrade facilities in advance of construction, which are recorded to current or non-current liabilities depending on the expected refund date.

Fair Value Through Net Income Securities — We have certain investments in mutual funds, including fixed income securities and equity securities that are classified as fair value through net income securities. The fixed income security investments primarily fund our two supplemental nonqualified, noncontributory, retirement benefit plans for selected management employees as described in Note 12 . Beginning on January 1, 2018, all gains and losses associated with our mutual funds as described in Note 13 are recorded in earnings. Previously, unrealized gains and losses on certain available-for-sale investments were recorded in AOCI.

Impairment of Long-Lived Assets — Other than goodwill, our long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate the carrying amount of an asset may not be recoverable. If the carrying amount of the asset exceeds the expected undiscounted future cash flows generated by the asset, the asset is written down to its estimated fair value and an impairment loss is recognized in our consolidated statements of comprehensive income .

Goodwill and Other Intangible Assets — Goodwill is not subject to amortization; however, goodwill is required to be assessed for impairment, and a resulting write-down, if any, is to be reflected in operating expense. We have goodwill recorded relating to our acquisitions of ITCTransmission and METC and ITC Midwest’s acquisition of the IP&L transmission assets. Goodwill is reviewed at the reporting unit level at least annually for impairment and whenever facts or circumstances indicate that the value of goodwill may be

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impaired. Our reporting units are ITCTransmission, METC and ITC Midwest as each entity represents an individual operating segment to which goodwill has been assigned.

In order to perform an impairment analysis, we have the option of performing a qualitative assessment to determine whether the existence of events or circumstances leads to a determination that it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, in which case no further testing is required. If an entity bypasses the qualitative assessment or performs a qualitative assessment but determines that it is more likely than not that a reporting unit’s fair value is less than its carrying amount, a quantitative, fair value-based test is performed to assess and measure goodwill impairment, if any. If a quantitative assessment is performed, we determine the fair value of our reporting units using valuation techniques based on discounted future cash flows under various scenarios and consider estimates of market-based valuation multiples for companies within the peer group of our reporting units.

We completed our annual goodwill impairment test for our reporting units as of October 1, 2018 and determined that no impairment exists. There were no events subsequent to October 1, 2018 that indicated impairment of our goodwill. Our intangible assets other than goodwill have finite lives and are amortized over their useful lives. Refer to Note 9 for additional discussion on our goodwill and intangible assets.

Deferred Financing Fees and Discount or Premium on Debt — Costs related to the issuance of long-term debt are generally recorded as a direct deduction from the carrying amount of the related debt and amortized over the life of the debt issue. Debt issuance costs incurred prior to the associated debt funding are presented as an asset. Unamortized debt issuance costs associated with the revolving credit agreements, commercial paper and other similar arrangements are presented as an asset (regardless of whether there are any amounts outstanding under those credit facilities) and amortized over the life of the particular arrangement. The debt discount or premium related to the issuance of long-term debt is recorded to long-term debt and amortized over the life of the debt issue. We recorded $5 million to interest expense for the amortization of deferred financing fees and debt discounts during the year ended December 31, 2018 and $4 million during each of the years ended December 31, 2017 and 2016 .

Asset Retirement Obligations — A conditional asset retirement obligation is a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within our control. We have identified conditional asset retirement obligations primarily associated with the removal of equipment containing PCBs and asbestos. We record a liability at fair value for a legal asset retirement obligation in the period in which it is incurred. When a new legal obligation is recorded, we capitalize the costs of the liability by increasing the carrying amount of the related long-lived asset. We accrete the liability to its present value each period and depreciate the capitalized cost over the useful life of the related asset. At the end of the asset’s useful life, we settle the obligation for its recorded amount. We recognize regulatory assets for the timing differences between the incurred costs to settle our legal asset retirement obligations and the recognition of such obligations as applicable for our Regulated Operating Subsidiaries. There were no significant changes to our asset retirement obligations in 2018 . Our asset retirement obligations as of December 31, 2018 and 2017 of $5 million and $6 million , respectively, are included in other liabilities.

Financial Instruments — For derivative instruments that have been designated and qualify as cash flow hedges of the exposure to variability in expected future cash flows, the gain or loss on the derivative is initially reported, net of tax, as a component of other comprehensive income (loss) and reclassified to the consolidated statements of comprehensive income 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 10 for additional discussion regarding derivative instruments. Cash flows related to derivative instruments that are designated in hedging relationships are generally classified on the consolidated statements of cash flows in the same category as the cash flows from the associated hedged item.

Contingent Obligations — We are subject to a number of federal and state laws and regulations, as well as other factors and conditions that potentially subject us to environmental, litigation and other risks. We periodically evaluate our exposure to such risks and record liabilities for those matters when a loss is considered probable and reasonably estimable. Our liabilities exclude any estimates for legal costs not yet incurred associated with handling these matters. The adequacy of liabilities can be significantly affected by

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external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect our consolidated financial statements.

Revenues — Substantially all of our revenue from contracts with customers is generated from providing transmission services to customers based on tariff rates, as approved by the FERC. Revenues from the transmission of electricity are recognized as services are provided based on our FERC-approved cost-based Formula Rates. We record a reserve for revenue subject to refund when such refund is probable and can be reasonably estimated. This reserve is recorded as a reduction to operating revenues.

The cost-based Formula Rates at our Regulated Operating Subsidiaries include a true-up mechanism that compares the actual revenue requirements of our Regulated Operating Subsidiaries to their billed revenues for each year to determine any over- or under-collection of revenue requirements and we record a revenue accrual or deferral for the difference. The true-up mechanisms under our Formula Rates are considered alternative revenue programs of rate-regulated utilities. Operating revenues arising from these alternative revenue programs are presented on our consolidated statements of comprehensive income in the line “Formula Rate true-up”, which is separate from the reporting of our tariff revenues, which are presented in the line “Transmission and other services”. Only the initial origination of our alternative revenue program revenue is reported in the Formula Rate true-up line on our consolidated statements of comprehensive income . When those amounts are subsequently included in the price of utility service and billed or refunded to customers, we account for that event as the recovery or settlement of the associated regulatory asset or regulatory liability, respectively. Refer to Note 6 under “Cost-Based Formula Rates with True-Up Mechanism” and Note 4 under “Formula Rate True-Up” for a discussion of our revenue accounting under our cost-based Formula Rates.

Share-Based Payment and Employee Share Purchase Plan — Under the terms of our 2017 Omnibus Plan, we may grant long term incentive awards of PBUs and SBUs. The awards are classified as liability awards based on the cash settlement feature. The award units earn dividend equivalents which are also settled in cash at the end of the vesting period. Compensation cost is recognized over the expected vesting period and remeasured each reporting period based on Fortis’ stock price. The PBUs are also remeasured each reporting period based on the applicable market and performance conditions in the awards. Compensation cost is adjusted for forfeitures in the period in which they occur and the final measure of compensation cost for the awards is based on the cash settlement amount.

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

Refer to Note 15 for additional discussion of the plans.

Comprehensive Income (Loss) — Comprehensive income (loss) is the change in common stockholder’s equity during a period arising from transactions and events from non-owner sources, including net income, any gain or loss recognized for the effective portion of our interest rate swaps, and prior to 2018, any unrealized gain or loss associated with available-for-sale securities.

Income Taxes — Deferred income taxes are recognized for the expected future tax consequences of events that have been recognized in the consolidated financial statements or tax returns. Deferred income tax assets and liabilities are determined based on the differences between the financial statements and the tax bases of various assets and liabilities, using the tax rates expected to be in effect for the year in which the differences are expected to reverse, and classified as non-current in our consolidated statements of financial position.

The accounting standards for uncertainty in income taxes prescribe a recognition threshold and a measurement attribute for tax positions taken, or expected to be taken, in a tax return that may not be sustainable. As of December 31, 2018 , we have not recognized any uncertain income tax positions.

We have historically filed income tax returns with the IRS and continue to file with various state and city jurisdictions. However, subsequent to the Merger, we are now part of the FortisUS consolidated federal tax return starting with the year ended December 31, 2016 and we are a party to an intercompany tax sharing

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agreement that establishes the method for determining tax liabilities that are due and allocating tax attributes that are utilized on the consolidated income tax return. Our prior consolidated federal tax returns are no longer subject to U.S. federal tax examinations for tax years 2013 and earlier. The FortisUS 2016 tax return of which we are a part, is currently under audit by the IRS. State and city jurisdictions that remain subject to examination range from tax years 2014 to 2017. In the event we are assessed interest or penalties by any income tax jurisdictions, interest and penalties would be recorded as interest expense and other expense, respectively, in our consolidated statements of comprehensive income .

Refer to Notes 7 and 11 for additional discussion on income taxes and tax reform.

4 .     REVENUE

Our total revenues are comprised of revenues which arise from three classifications including transmission services, other services revenue, and Formula Rate true-up. As other services revenue is immaterial, it is presented in combination with transmission services on the consolidated statements of comprehensive income .

Transmission Services

Through our Regulated Operating Subsidiaries, we generate nearly all our revenue from providing electric transmission services over our transmission systems. As independent transmission companies, our transmission services are provided and revenues are received based on our tariffs, as approved by the FERC. The transmission revenue requirements at our Regulated Operating Subsidiaries are set annually using Formula Rates and remain in effect for a one-year period. By updating the inputs to the formula and resulting rates on an annual basis, the revenues at our Regulated Operating Subsidiaries reflect changing operating data and financial performance, including the amount of network load on their transmissions systems (for our MISO Regulated Operating Subsidiaries), operating expenses and additions to property, plant and equipment when placed in service, among other items.

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

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

Other Services Revenue

Other services revenue consists of rental revenues, easement revenues, and amounts from providing ancillary services. A portion of other services revenue is treated as a revenue credit and reduces gross revenue requirement when calculating net revenue requirement under our Formula Rates. Total other services revenue was $5 million for the year ended December 31, 2018 and $6 million for both the years ended December 31, 2017 and 2016 .

Formula Rate True-Up

The true-up mechanism under our Formula Rates is considered an alternative revenue program of a rate-regulated utility given it permits our Regulated Operating Subsidiaries to adjust future rates in response to past activities or completed events in order to collect our actual revenue requirements under our Formula Rates. In accordance with our accounting policy, only the current year origination of the true-up is reported as a Formula Rate true-up. See “Cost-based Formula Rates with True-Up Mechanism” in Note 6 for more information on our Formula Rates.

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5 .     ACCOUNTS RECEIVABLE

The following table presents the components of accounts receivable on the balance sheet:

	Year Ended December 31,
(In millions)	2018				2017				2016				2015
Trade accounts receivable	$	2			$	2			$	2			$	2
Unbilled accounts receivable	92				108				92				92
Due from affiliates	1				—				1				—
Other	7				9				13				10
Total accounts receivable	$	102			$	119			$	108			$	104

6 .     REGULATORY MATTERS

Cost-Based Formula Rates with True-Up Mechanism

The transmission revenue requirements at our Regulated Operating Subsidiaries are set annually using Formula Rates and remain in effect for a 1 -year period. By updating the inputs to the formula and resulting rates on an annual basis, the revenues at our Regulated Operating Subsidiaries reflect changing operational data and financial performance, including the amount of network load on their transmission systems (for our MISO Regulated Operating Subsidiaries), operating expenses and additions to property, plant and equipment when placed in service, among other items. The formula used to derive the rates does not require further action or FERC filings each year, although the formula inputs remain subject to legal challenge at the FERC. Our Regulated Operating Subsidiaries will continue to use the formula to calculate their respective annual revenue requirements unless the FERC determines the resulting rates to be unjust and unreasonable and another mechanism is determined by the FERC to be just and reasonable. See “Rate of Return on Equity Complaints” in Note 18 for detail on ROE matters for our MISO Regulated Operating Subsidiaries and "Incentive Adders for Transmission Rates" discussed in Note 6 herein.

The cost-based Formula Rates at our Regulated Operating Subsidiaries include a true-up mechanism that compares the actual revenue requirements of our Regulated Operating Subsidiaries to their billed revenues for each year to determine any over- or under-collection of revenue requirements . Revenue is recognized for services provided during each reporting period based on actual revenue requirements calculated using the formula. Our Regulated Operating Subsidiaries accrue or defer revenues to the extent that the actual revenue requirement for the reporting period is higher or lower, respectively, than the amounts billed relating to that reporting period. The amount of accrued or deferred revenues is reflected in future revenue requirements and thus flows through to customer bills within 2 years under the provisions of our Formula Rates.

The net changes in regulatory assets and liabilities associated with our Regulated Operating Subsidiaries’ Formula Rate revenue accruals and deferrals, including accrued interest, were as follows during the year ended December 31, 2018 :

(In millions)	Total
Net regulatory liability as of December 31, 2017	$	(35	)
Net refund of 2016 revenue deferrals and accruals, including accrued interest	21
Net revenue deferral for the year ended December 31, 2018	(36		)
Net accrued interest payable for the year ended December 31, 2018	(2		)
Net regulatory liability as of December 31, 2018	$	(52	)

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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, 2018 and 2017 as follows:

(In millions)	2018				2017
Current regulatory assets	$	12			$	18
Non-current regulatory assets	12				11
Current regulatory liabilities	(27		)		(38		)
Non-current regulatory liabilities	(49		)		(26		)
Net regulatory liability	$	(52	)		$	(35	)

Incentive Adders for Transmission Rates

The FERC has authorized the use of ROE incentives, or adders, that can be applied to the rates of TOs when certain conditions are met. Our MISO Regulated Operating Subsidiaries and ITC Great Plains utilize adders related to independent transmission ownership and RTO participation.

MISO Regulated Operating Subsidiaries

For periods prior to the Initial Complaint, ITCTransmission and METC were authorized to include a 100 basis point adder for independent transmission ownership and ITCTransmission was also authorized to include a 50 basis point adder for RTO participation.

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 adder for RTO participation in each of the TOs’ Formula Rates. On January 5, 2015, the FERC approved the use of this adder, effective January 6, 2015.

ITC Midwest filed a request with the FERC, under FPA Section 205, in January 2015 for authority to include a 100 basis point adder for independent transmission ownership. On March 31, 2015, the FERC approved the use of a 50 basis point adder for independent transmission ownership, effective April 1, 2015.

Beginning September 28, 2016, these 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% .

Effective for the period following the September 2016 Order, the authorized ROE used by ITCTransmission, METC, and ITC Midwest were 11.35% , 11.35% and 11.32% , respectively. These were inclusive of adders at ITCTransmission, METC and ITC Midwest of 150 basis points, 150 basis points and 100 basis points, respectively, subject to the maximum ROE limitation in the September 2016 Order of 11.35% . The adders at each of ITCTransmission and METC included a 100 basis point adder for independent transmission ownership and a 50 basis point adder for RTO participation. The adders at ITC Midwest included a 50 basis point adder for independent transmission ownership and a 50 basis point adder for RTO participation.

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

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Based on the October 18, 2018 FERC order, the authorized ROE for the MISO Regulated Operating Subsidiaries has been revised to 11.07% ( 10.32% base ROE with a 50 basis point adder for RTO participation and a 25 basis point adder for independent transmission ownership). See Note 18 for information regarding the ROE complaints.

ITC Great Plains

On December 19, 2018, the KCC filed a Motion to Show Cause with the FERC to reduce the ITC Great Plains adder for independent transmission ownership. The motion argues that because ITC Great Plains is similarly situated to our MISO Regulated Operating Subsidiaries with respect to ownership by Fortis and GIC, the same rationale by which the FERC lowered the MISO Regulated Operating Subsidiaries adders for independent transmission ownership, as discussed above, applies with equal force to ITC Great Plains. The adder for independent transmission ownership allows up to 100 basis points to be added to the ITC Great Plains authorized ROE, subject to any ROE cap established by the FERC. On January 16, 2019, ITC Great Plains filed a motion to strike the KCC motion. We do not expect the resolution of this motion to have a material adverse impact on our consolidated results of operation, cash flows or financial condition.

The authorized ROE used by ITC Great Plains is 12.16% and is composed of a base ROE of 10.66% with a 50 basis point adder for RTO participation and 100 basis point adder for independent transmission ownership.

Reposting of Rates for Regulated Operating Subsidiaries

As a result of the reduction in the federal tax rate arising from the enactment of the TCJA, the 2018 projected Formula Rates for our MISO Regulated Operating Subsidiaries were reposted. On March 15, 2018, the FERC granted a waiver which allowed us to adjust the rates effective back to January 1, 2018 for our MISO Regulated Operating Subsidiaries and allowed MISO to return to customers excess amounts previously collected in 2018. Our rates included in MISO invoices for services provided starting in March 2018 and going forward reflected the lower corporate tax rate. Resettlement of invoices for services provided in January and February 2018 occurred in April 2018 when the March 2018 services were billed. We recorded a reduction of revenue of $16 million in the first quarter of 2018, which was offset through a lower income tax provision for our MISO Regulated Operating Subsidiaries and as such did not impact net income.

In addition, the 2018 projected Formula Rates for ITC Great Plains, which are settled by SPP, were reposted. On May 25, 2018, the FERC granted a waiver which allowed us to adjust the rate effective back to January 1, 2018 for ITC Great Plains and allowed SPP to return to customers excess amounts previously collected in 2018. Our rates included in SPP invoices for services provided starting in June and going forward reflected the lower corporate tax rate. During the second quarter of 2018, we recorded a reduction of revenue of $4 million related to the resettlement of invoices for services provided in January through May 2018. Resettlement of these invoices occurred during the fourth quarter of 2018. This reduction of revenue was offset through a lower income tax provision for ITC Great Plains and as such did not impact net income.

MISO Funding Policy for Generator Interconnections

On June 18, 2015, the FERC issued an order initiating a proceeding, pursuant to Section 206 of the FPA, to examine MISO’s funding policy for generator interconnections, which allowed a TO to unilaterally elect to fund network upgrades and recover such costs from the interconnection customer. In this order, the FERC found that the MISO funding policy may be unduly discriminatory and suggested the MISO funding policy be revised to require mutual agreement between the interconnection customer and TO for the TO funded network upgrades. In the absence of such mutual agreement, the facilities would be funded solely by the interconnection customer. On January 8, 2016, MISO made a compliance filing to revise its funding policy to adopt the FERC suggestion to require mutual agreement between the customer and TO, with an effective date of June 24, 2015. Our MISO Regulated Operating Subsidiaries, along with another MISO TO, have appealed the FERC’s orders on this issue and on January 26, 2018, the D.C. Circuit Court vacated the orders and remanded this case to the FERC. On March 24, 2018, our MISO Regulated Operating Subsidiaries and the other MISO TO that participated in the appeal at the D.C. Circuit Court filed a motion with the FERC that asks the FERC to implement the D.C. Circuit Court’s decision and order MISO to amend its tariff to reinstate the self-fund option effective June 24, 2015 and to permit MISO TOs that were unable to elect self-funding in GIAs that were executed since June 24, 2015 to amend those GIAs to include the self-fund option. On August 31, 2018, the FERC issued an order on remand that directed MISO to restore the right of a TO to unilaterally elect to fund the capital cost of network upgrades, effective prospectively from the date of the FERC order. A request for rehearing of the August 31, 2018 FERC order was

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filed on October 2, 2018. The FERC also requested additional briefing regarding the treatment of contracts entered into between June 24, 2015 and the date of the FERC order, and briefs have been filed. 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.

Calculation of Accumulated Deferred Income Tax Balances in Projected Formula Rates

On June 21, 2018, the FERC issued an order initiating a proceeding and paper hearings, pursuant to Section 206 of the FPA, to examine the methodology used by a group of TOs, including ITCTransmission and ITC Midwest, for calculating balances of ADIT in forward-looking Formula Rates. The order is based on a previous FERC decision for another group of TOs in which the FERC concluded that the two-step averaging methodology for ADIT is no longer necessary to comply with IRS normalization rules in light of IRS guidance issued in 2017. On August 27, 2018, ITCTransmission and ITC Midwest, along with other MISO TOs, filed an initial brief in the paper hearing proceeding. In addition, on August 27, 2018, our MISO Regulated Operating Subsidiaries submitted a filing with the FERC under Section 205 of the FPA to eliminate the use of the two-step averaging methodology in the calculation of ADIT balances for the projected test year and also to modify the manner by which they calculate average ADIT balances in their annual transmission Formula Rate true-up calculation, subject to receiving guidance from the IRS to respond to the FERC order. On December 20, 2018, the FERC issued an order that (1) indicated that it did not believe it was necessary for the MISO Regulated Subsidiaries to delay implementation of the template changes pending IRS approval, (2) ordered ITCTransmission and ITC Midwest to make a compliance filing to implement the changes and (3) formally instituted a proceeding against METC pursuant to Section 206 to implement the changes. On January 22, 2019, ITCTransmission and ITC Midwest submitted their compliance filing, and METC submitted revised tariff sheets in a filing with the FERC under Section 205 of the FPA to comply with the FERC’s order. The MISO Regulated Operating Subsidiaries’ filings also included tariff revisions to carry proration to their true ups. We do not expect the resolution of this proceeding to have a material adverse impact on our consolidated results of operations, cash flows or financial condition.

Rate of Return on Equity Complaints

See “Rate of Return on Equity Complaints” in Note 18 for a discussion of the complaints.

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7 .     REGULATORY ASSETS AND LIABILITIES

Regulatory Assets

The following table summarizes the regulatory asset balances at December 31, 2018 and 2017 :

(In millions)	2018				2017
Regulatory Assets:
Current:
Revenue accruals (including accrued interest of less than $1 as of December 31, 2018 and 2017) (a)	$	12			$	18
Total current	12				18
Non-current:
Revenue accruals (including accrued interest of less than $1 as of December 31, 2018 and 2017) (a)	12				11
ITCTransmission ADIT deferral (net of accumulated amortization of $48 and $45 as of December 31, 2018 and 2017, respectively)	13				16
METC ADIT deferral (net of accumulated amortization of $29 and $26 as of December 31, 2018 and 2017, respectively)	14				17
METC regulatory deferrals (net of accumulated amortization of $9 as of December 31, 2018 and 2017)	6				7
Income taxes recoverable related to AFUDC equity	91				80
ITC Great Plains start-up, development and pre-construction (net of accumulated amortization of $5 and $3 as of December 31, 2018 and 2017, respectively)	8				10
Pensions and postretirement	25				30
Income taxes recoverable related to implementation of the Michigan Corporate Income Tax and other state excess deficient taxes	7				7
Accrued asset removal costs	24				19
Total non-current	200				197
Total	$	212			$	215

____________________________

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

ITCTransmission ADIT Deferral

The carrying amount of the ITC Transmission ADIT Deferral is the remaining unamortized balance of the portion of ITCTransmission’s purchase price in excess of fair value of net assets acquired from DTE Energy approved for inclusion in future rates by the FERC. The original amount recorded for this regulatory asset of $61 million is recognized in rates and amortized on a straight-line basis over 20 years beginning March 1, 2003. ITCTransmission includes the remaining unamortized balance of this regulatory asset in rate base. ITCTransmission recorded amortization expense of $3 million annually during 2018 , 2017 and 2016 , which is included in depreciation and amortization and recovered through ITCTransmission’s cost-based Formula Rate template.

METC ADIT Deferral

The carrying amount of the METC ADIT Deferral is the remaining unamortized balance of the portion of METC’s purchase price in excess of the fair value of net assets acquired at the time MTH acquired METC from Consumers Energy. The original amount approved for recovery recorded for this regulatory asset of $43 million is recognized in rates and amortized on a straight-line basis over 18 years beginning January 1, 2007. METC includes the remaining unamortized balance of this regulatory asset in rate base. METC recorded amortization expense of $2 million annually during 2018 , 2017 and 2016 , which is included in depreciation and amortization and recovered through METC’s cost-based Formula Rate template.

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METC Regulatory Deferrals

The carrying amount of the METC Regulatory Deferrals is the amount METC has deferred, as a regulatory asset, depreciation and related interest expense associated with new transmission assets placed in service from January 1, 2001 through December 31, 2005 that were included on METC’s balance sheet at the time MTH acquired METC from Consumers Energy. The original amount recorded for this regulatory asset of $15 million , and approved for inclusion in future rates by the FERC, is recognized in rates and amortized over 20 years beginning January 1, 2007. METC includes the remaining unamortized balance of this regulatory asset in rate base. METC recorded amortization expense of $1 million annually during 2018 , 2017 and 2016 , which is included in depreciation and amortization and recovered through METC’s cost-based Formula Rate template.

Income Taxes Recoverable Related to AFUDC Equity

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

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

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

Pensions and Postretirement

Accounting standards for defined benefit pension and other postretirement plans for rate-regulated entities allow for amounts that otherwise would have been charged and/or credited to AOCI to be recorded as a regulatory asset or liability. As the unrecognized amounts recorded to this regulatory asset are recognized, expenses will be recovered from customers in future rates under our cost based Formula Rates. This regulatory asset is not included when determining rate base.

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

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

Accrued Asset Removal Costs

The carrying amount of the accrued asset removal costs represents the difference between incurred costs to remove property, plant and equipment and the estimated removal costs included and collected in rates. The portion of depreciation expense included in our depreciation rates related to asset removal costs reduces this regulatory asset and removal costs incurred are added to this regulatory asset. In addition, this regulatory asset has also been adjusted for timing differences between incurred costs to settle legal asset retirement obligations and the recognition of such obligations under the standards set forth by the FASB. Our Regulated Operating Subsidiaries include this item, excluding the cost component related to the recognition of our legal asset retirement obligations

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under the standards set forth by the FASB, as a reduction to accumulated depreciation for rate-making purposes, when determining rate base.

Regulatory Liabilities

The following table summarizes the regulatory liability balances at December 31, 2018 and 2017 :

(In millions)	2018				2017
Regulatory Liabilities:
Current:
Revenue deferrals (including accrued interest of $2 as of December 31, 2018 and 2017) (a)	$	27			$	38
Estimated refund related to return on equity complaints (including accrued interest of $18 and $11 as of December 31, 2018 and 2017, respectively.) (b)	151				145
Total current	178				183
Non-current:
Revenue deferrals (including accrued interest of $1 as of December 31, 2018 and 2017) (a)	49				26
Accrued asset removal costs	71				72
Excess state income tax deductions	9				7
Income taxes refundable related to implementation of the TCJA	511				514
Total non-current	640				619
Total	$	818			$	802

____________________________

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

(b)	Refer to discussion of the estimated refund in Note 18 under “Rate of Return on Equity Complaints.”

Accrued Asset Removal Costs

The carrying amount of the accrued asset removal costs represents the difference between incurred costs to remove property, plant and equipment and the estimated removal costs included and collected in rates. The portion of depreciation expense included in our depreciation rates related to asset removal costs is added to this regulatory liability and removal expenditures incurred are charged to this regulatory liability. Our Regulated Operating Subsidiaries include this item within accumulated depreciation for rate-making purposes and determining rate base.

Excess State Income Tax Deductions

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

Income Taxes Refundable Related to Implementation of the TCJA

In December 2017, the President of the United States signed into law the TCJA, which enacted significant changes to the Internal Revenue Code including a reduction in the U.S. federal corporate income tax rate from 35% to 21% effective for tax years beginning after 2017. The Company was required to revalue its deferred tax assets and liabilities at the new federal corporate income tax rate as of the date of the enactment of the TCJA, which resulted in lower net deferred tax liabilities and the establishment of a regulatory liability for excess deferred taxes at our Regulated Operating Subsidiaries. The excess deferred taxes are generally the result of accelerated federal tax deductions realized by our Regulated Operating Subsidiaries in periods when the U.S. federal corporate income tax rate was 35% and now would be returned to customers in a period where the U.S. federal corporate income tax rate is 21%. As the excess deferred taxes must be returned to customers this regulatory liability is recognized. For our Regulated Operating Subsidiaries, our deferred taxes are subject to a normalization method

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of accounting for the excess tax reserves resulting from the change in the federal statutory tax rate which involves the use of ARAM for the determination of the timing of the return of the excess deferred taxes to customers associated with public utility property. In addition, a portion of our excess deferred taxes at our Regulated Operating Subsidiaries are associated with other types of deferred taxes that are not related to public utility property and are subject to amortization. We have elected to amortize these excess deferred taxes using RSGM and have determined that it is a reasonable method of amortization. During 2018, we recorded less than $1 million of amortization related to the excess deferred taxes under ARAM and RSGM. The net regulatory liability is included within deferred taxes for rate-making purposes when determining rate base.

8 .     PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment — net consisted of the following at December 31, 2018 and 2017 :

(In millions)	2018				2017
Property, plant and equipment
Regulated Operating Subsidiaries:
Property, plant and equipment in service	$	9,113			$	8,334
Construction work in progress	465				546
Capital equipment inventory	79				74
Other	18				16
ITC Holdings and other	14				14
Total	9,689				8,984
Less: Accumulated depreciation and amortization	(1,779		)		(1,675		)
Property, plant and equipment, net	$	7,910			$	7,309

Additions to property, plant and equipment in service and construction work in progress during 2018 and 2017 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 MVPs.

9 .     GOODWILL AND INTANGIBLE ASSETS

Goodwill

At December 31, 2018 and 2017 , we had goodwill balances recorded at ITCTransmission, METC and ITC Midwest of $173 million , $454 million and $323 million , respectively, which resulted from the ITCTransmission and METC acquisitions and ITC Midwest’s acquisition of the IP&L transmission assets, respectively.

Intangible Assets

Pursuant to the METC acquisition in October 2006, we have identified intangible assets with finite lives derived from the portion of regulatory assets recorded on METC’s historical FERC financial statements that were not recorded on METC’s historical GAAP financial statements associated with the METC Regulatory Deferrals and the METC ADIT Deferral as described in Note 7 . The carrying amounts of the intangible asset for the METC Regulatory Deferrals and the METC ADIT Deferral were $16 million and $6 million (net of accumulated amortization of $24 million and $13 million ), respectively, as of December 31, 2018 , and $18 million and $8 million (net of accumulated amortization of $22 million and $11 million ), respectively, as of December 31, 2017 . The amortization periods for the METC Regulatory Deferrals and the METC ADIT Deferral are 20 years and 18 years , respectively, beginning January 1, 2007. METC earns an equity return on the remaining unamortized balance of both intangible assets and recovers the amortization expense through METC’s cost-based Formula Rate template.

ITC Great Plains has recorded intangible assets for payments made by and obligations of ITC Great Plains to certain TOs to acquire rights, which are required under the SPP tariff to designate ITC Great Plains to build, own and operate projects within the SPP region, including three regional cost sharing projects in Kansas. The carrying amount of these intangible assets was $14 million (net of accumulated amortization of $2 million , respectively) as of December 31, 2018 and 2017 . The amortization period for these intangible assets is 50 years .

We recognized $4 million , $3 million , and $3 million of amortization expense of our intangible assets during the years ended December 31, 2018 , 2017 and 2016 , respectively. We have other intangible assets that are not subject

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to amortization at December 31, 2018 and 2017. We expect the annual amortization of our intangible assets that have been recorded as of December 31, 2018 to be as follows:

(In millions)
2019	$	3
2020	4
2021	3
2022	3
2023	4
2024 and thereafter	19
Total	$	36

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10 .     DEBT

The following amounts were outstanding at December 31, 2018 and 2017 :

(In millions)	2018				2017
ITC Holdings 6.375% Senior Notes, due September 30, 2036	$	200			$	200
ITC Holdings 5.50% Senior Notes, due January 15, 2020	200				200
ITC Holdings 4.05% Senior Notes, due July 1, 2023	250				250
ITC Holdings 3.65% Senior Notes, due June 15, 2024	400				400
ITC Holdings 5.30% Senior Notes, due July 1, 2043	300				300
ITC Holdings 3.25% Notes, due June 30, 2026	400				400
ITC Holdings 2.70% Senior Notes, due November 15, 2022	500				500
ITC Holdings 3.35% Senior Notes, due November 15, 2027	500				500
ITC Holdings Revolving Credit Agreement, due October 21, 2022 (a)	37				—
ITCTransmission 6.125% First Mortgage Bonds, Series C, due March 31, 2036	100				100
ITCTransmission 5.75% First Mortgage Bonds, Series D, due April 1, 2018 (b)	—				100
ITCTransmission 4.625% First Mortgage Bonds, Series E, due August 15, 2043	285				285
ITCTransmission 4.27% First Mortgage Bonds, Series F, due June 10, 2044	100				100
ITCTransmission 4.00% First Mortgage Bonds, Series G, due March 30, 2053	225				—
ITCTransmission Term Loan Credit Agreement, due March 23, 2019	—				50
ITCTransmission Revolving Credit Agreement, due October 21, 2022 (a)	27				36
METC 5.64% Senior Secured Notes, due May 6, 2040	50				50
METC 3.98% Senior Secured Notes, due October 26, 2042	75				75
METC 4.19% Senior Secured Notes, due December 15, 2044	150				150
METC 3.90% Senior Secured Notes, due April 26, 2046	200				200
METC Revolving Credit Agreement, due October 21, 2022 (a)	70				48
ITC Midwest 6.15% First Mortgage Bonds, Series A, due January 31, 2038	175				175
ITC Midwest 7.27% First Mortgage Bonds, Series C, due December 22, 2020	35				35
ITC Midwest 4.60% First Mortgage Bonds, Series D, due December 17, 2024	75				75
ITC Midwest 3.50% First Mortgage Bonds, Series E, due January 19, 2027	100				100
ITC Midwest 4.09% First Mortgage Bonds, Series F, due April 30, 2043	100				100
ITC Midwest 3.83% First Mortgage Bonds, Series G, due April 7, 2055	225				225
ITC Midwest 4.16% First Mortgage Bonds, Series H, due April 18, 2047	200				200
ITC Midwest 4.32% First Mortgage Bonds, Series I, due November 1, 2051	175				—
ITC Midwest Revolving Credit Agreement, due October 21, 2022 (a)	34				88
ITC Great Plains 4.16% First Mortgage Bonds, Series A, due November 26, 2044	150				150
ITC Great Plains Revolving Credit Agreement, due October 21, 2022 (a)	40				49
Total principal	5,378				5,141
Unamortized deferred financing fees and discount	(40		)		(40		)
Total debt	$	5,338			$	5,101

____________________________

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

(b)	As of December 31, 2018 we had no debt maturing within one year. As of December 31, 2017 we had $100 million of debt included within debt maturing within one year and 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, 2018 are as follows:

(In millions)
2019	$	—
2020	235
2021	—
2022	708
2023	250
2024 and thereafter	4,185
Total	$	5,378

ITC Holdings

Senior Unsecured Notes

On November 14, 2017, ITC Holdings completed the private offering of $500 million aggregate principal amount of unsecured 2.70% Senior Notes, due November 15, 2022, and $500 million aggregate principal amount of unsecured 3.35% Senior Notes, due November 15, 2027, (collectively, the “2017 Senior Notes”). The 2017 Senior Notes are redeemable prior to the due date, in whole or in part and at the option of ITC Holdings, by paying an applicable make whole premium. The net proceeds from this offering were used to redeem in full $385 million aggregate principal amount of ITC Holdings 6.05% Senior Notes due January 31, 2018, and to pay the associated call premiums, to repay the amount outstanding under ITC Holdings’ 2017 term loan credit agreement, to repay $7 million under ITC Holdings’ revolving credit agreement, and to repay $352 million under ITC Holdings’ commercial paper program, with remaining proceeds used for general corporate purposes. As a result of the redemption of the $385 million 6.05% Senior Notes, we recorded a $2 million loss on extinguishment of the debt at the time of the redemption, which is included in Interest expense, net in the consolidated statements of comprehensive income . The 2017 Senior Notes were issued under ITC Holdings’ indenture, dated April 18, 2013.

In connection with the offering of the 2017 Senior Notes, ITC Holdings also entered into a registration rights agreement with the representatives of the initial purchasers named therein. Pursuant to this registration rights agreement, ITC Holdings agreed to use its commercially reasonable efforts to file with the SEC and cause to become effective a registration statement with respect to registered exchange offers to exchange each series of 2017 Senior Notes issued in the offering for an issue of notes having terms substantially identical to the applicable series of 2017 Senior Notes (except for provisions relating to the transfer restrictions, registration rights and payment of additional interest) (the “Exchange Offers”). On June 19, 2018, ITC Holdings completed the Exchange Offers, pursuant to an effective registration statement on Form S-4, under which all of the 2017 Senior Notes issued in the offering were exchanged for an issue of notes having terms substantially identical to the applicable series of 2017 Senior Notes (except for provisions in the 2017 Senior Notes relating to transfer restrictions, registration rights and payment of additional interest).

Commercial Paper Program

ITC Holdings has an ongoing commercial paper program for the issuance and sale of unsecured commercial paper in an aggregate amount not to exceed $400 million outstanding at any one time. As of December 31, 2018 , ITC Holdings did not have any commercial paper issued or outstanding. The proceeds from issuances under the program during the year ended December 31, 2017 were used to repay and retire the $50 million of ITC Holdings’ 6.23% Senior Notes, due September 20, 2017, and for general corporate purposes, including the repayment of borrowings under ITC Holdings’ revolving credit agreement. ITC repaid borrowings under the commercial paper program of $352 million in November 2017 with proceeds from the ITC Holdings 2017 Senior Notes issued on November 14, 2017.

Term Loan Credit Agreement

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

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ITCTransmission

First Mortgage Bonds

On March 29, 2018, ITCTransmission issued $225 million aggregate principal amount of 4.00% First Mortgage Bonds due March 30, 2053. The proceeds were used to refinance $100 million of ITCTransmission’s 5.75% First Mortgage Bonds due April 1, 2018 and repay the existing indebtedness under ITCTransmission’s revolving credit agreement in March 2018. Proceeds were also used to repay ITCTransmission’s $50 million of borrowings under its term loan credit agreement due March 23, 2019. Remaining proceeds were used to partially fund capital expenditures and for general corporate purposes. ITCTransmission’s First Mortgage bonds were issued under its first mortgage and deed of trust and secured by a first mortgage lien on substantially all of its real property and tangible personal property.

On March 23, 2017, ITCTransmission entered into an unsecured, unguaranteed term loan credit agreement due March 23, 2019, under which ITCTransmission borrowed $50 million . The proceeds were used for general corporate purposes, including the repayment of borrowings under ITCTransmission’s revolving credit agreement. This borrowing was repaid in full in April 2018 from the proceeds of the ITCTransmission First Mortgage Bonds issued on March 29, 2018. The weighted-average interest rate throughout the life of the loan was 2.03% .

METC

Senior Secured Notes

On January 15, 2019, METC issued $50 million of 4.55% Senior Secured Notes, due January 15, 2049. METC has an additional $50 million delayed draw of Senior Secured Notes in July 2019 at 4.65% with terms and conditions identical to those of the 4.55% Senior Secured Notes except the interest rate which will include a 10 basis point premium and the due date which will be 30 years from the date of the issuance. The proceeds from the issuance will be used to repay borrowings under the METC revolving credit agreement, to partially fund capital expenditures and for general corporate purposes. All of METC’s Senior Secured Notes are issued under its first mortgage indenture and secured by a first mortgage lien on substantially all of its real property and tangible personal property. These issuances are not included in the table above.

ITC Midwest

First Mortgage Bonds

On November 1 and November 2, 2018, ITC Midwest issued an aggregate of $175 million of 4.32% First Mortgage Bonds due November 1, 2051. The proceeds were used to partially repay existing indebtedness under the ITC Midwest revolving credit agreement, partially fund capital expenditures and for general corporate purposes. ITC Midwest’s First Mortgage Bonds were issued under its first mortgage and deed of trust and secured by a first mortgage lien on substantially all of our real property and tangible personal property.

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

Derivative Instruments and Hedging Activities

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

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

Interest Rate Swaps (In millions, except percentages)		Amount				Weighted Average Fixed Rate of  Interest Rate Swaps			Comparable Reference Rate of Notes			Gain on Derivatives				Settlement Date
5-year interest rate swaps		$	375			1.85	%		2.06	%		$	4			November 2017
10-year interest rate swaps		375				2.22	%		2.31	%		3				November 2017
Total		$	750									$	7

The interest rate swaps qualified for cash flow hedge accounting treatment and the pre-tax gain of $7 million was recognized in November 2017 for the effective portion of the hedges and recorded net of tax in AOCI. This amount is being amortized as a component of interest expense over the life of the related debt. At December 31, 2018 , ITC Holdings did not have any interest rate swaps outstanding.

Revolving Credit Agreements

At December 31, 2018 , ITC Holdings and certain of its Regulated Operating Subsidiaries had the following unsecured revolving credit facilities available:

(In millions, except percentages)	Total Available Capacity				Outstanding Balance (a)				Unused Capacity					Weighted Average Interest Rate on Outstanding Balance (b)		Commitment Fee Rate (c)
ITC Holdings	$	400			$	37			$	363		(d)		3.7%		0.175	%
ITCTransmission	100				27				73					3.4%		0.10	%
METC	100				70				30					3.4%		0.10	%
ITC Midwest	225				34				191					3.4%		0.10	%
ITC Great Plains	75				40				35					3.4%		0.10	%
Total	$	900			$	208			$	692

____________________________

(a)	Included within long-term debt.

(b)	Interest charged on borrowings depends on the variable rate structure we elected at the time of each borrowing.

(c)	Calculation based on the average daily unused commitments, subject to adjustment based on the borrower’s credit rating.

(d)	ITC Holdings’ revolving credit agreement may be used for general corporate purposes, including to repay commercial paper issued pursuant to the commercial paper program described above, if necessary.

Our debt instruments contain numerous financial and operating covenants that place significant restrictions on certain transactions, such as incurring additional indebtedness, engaging in sale and lease-back transactions, creating liens or other encumbrances, entering into mergers, consolidations, liquidations or dissolutions, creating or acquiring subsidiaries and selling or otherwise disposing of all or substantially all of our assets. In addition, the covenants require us to meet certain financial ratios, such as maintaining certain debt to capitalization ratios and certain funds from operations to debt levels. As of December 31, 2018 , we were not in violation of any debt covenant.

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11 .     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)	2018				2017				2016
Income tax expense at federal statutory rate (a)	$	93			$	180			$	120
State income taxes (net of federal benefit) (b)	31				16				3
AFUDC equity	(6		)		(10		)		(11		)
Revaluation of deferred federal income taxes (c)	(2		)		8				—
Excess tax deductions for share-based compensation (d)	—				—				(23		)
Other, net (e)	(5		)		2				8
Total income tax provision	$	111			$	196			$	97

____________________________

(a)	The federal statutory rate is 21% for 2018, and 35% for 2017 and 2016.

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

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

(d)	Amount 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.

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

Components of the income tax provision were as follows:

(In millions)	2018				2017				2016
Current income tax expense (benefit) (a)	$	4			$	1			$	(122	)
Deferred income tax expense (b)(c)(d)	107				195				219
Total income tax provision	$	111			$	196			$	97

____________________________

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

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

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

(d)	Amount for the year ended December 31, 2016 includes utilization of $126 million of net operating losses, primarily resulting from the election of bonus depreciation.

Deferred tax assets and liabilities are recognized for the estimated future tax effect of temporary differences between the tax basis of assets or liabilities and the reported amounts in the consolidated financial statements.

In December 2017, the President of the United States signed into law the TCJA, which enacted significant changes to the Internal Revenue Code including a reduction in the U.S. federal corporate income tax rate from

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35% to 21% effective for tax years beginning after 2017. For additional information on the impacts of tax reform, see Note 7 . During the second quarter of 2018, Iowa enacted a reduction in corporate statutory income tax rates from 12.0% to 9.8% , effective January 1, 2021. Based upon the future change in rate, the Iowa NOLs at ITC Holdings were remeasured. As a result, we recorded additional income tax expense of $6 million during the year ended December 31, 2018 . For the years ended December 31, 2018 and 2017 , our effective tax rates were 25.2% and 38.1% , respectively.

In December 2017, the SEC staff issued Staff Accounting Bulletin No. 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act (SAB 118), which allowed us to record provisional amounts during a measurement period not to extend beyond one year of the enactment date. As a result, we previously provided a provisional estimate for bonus depreciation for our fixed assets placed in service between September 27, 2017 and December 31, 2017 which impacted our deferred tax liability for property, plant and equipment and deferred tax asset for federal income tax NOLs and other credits as a result of the TCJA in our consolidated financial statements. In the fourth quarter of 2018, we completed our analysis to determine the effect of the TCJA and recorded immaterial adjustments as of December 31, 2018.

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

(In millions)	2018				2017
Property, plant and equipment	$	(884	)		$	(798	)
Federal income tax NOLs and other credits	47				84
METC regulatory deferral (a)	(6		)		(6		)
Acquisition adjustments — ADIT deferrals (a)	(8		)		(10		)
Goodwill	(128		)		(120		)
Refund liabilities (a)	40				38
Regulatory liability gross up — TCJA	138				139
Pension and postretirement liabilities	18				16
State income tax NOLs (net of federal benefit)	43				50
True-up adjustment principal & interest	14				9
Other, net	5				(3		)
Net deferred tax liabilities (b)	$	(721	)		$	(601	)
Gross deferred income tax liabilities	$	(1,040	)		$	(952	)
Gross deferred income tax assets	319				351
Net deferred tax liabilities	$	(721	)		$	(601	)

____________________________

(a)	Described in Note 7 .

(b)

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

We have federal income tax NOLs and capital losses as of December 31, 2018. We expect to use our NOLs prior to their expirations starting in 2036. As of December 31, 2018, we had recorded a valuation allowance of less than $1 million , which fully offsets any of our federal capital loss that we do not expect to utilize with the filing of the 2018 tax return. We also have state income tax NOLs as of December 31, 2018, all of which we expect to use prior to their expiration starting in 2022 .

12 .     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

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employees and provides retirement benefits based on eligible compensation and interest credits. Our funding practice for the retirement plan is generally to fund the annual net pension cost though we may contribute additional amounts as necessary to meet the minimum funding requirements of the Employee Retirement Income Security Act of 1974 or as we deem appropriate. We made contributions of $4 million , $4 million and $3 million to the retirement plan in 2018 , 2017 and 2016 , respectively. We expect to contribute $4 million to the retirement plan in 2019 .

We also have two supplemental nonqualified, noncontributory, defined benefit pension plans for selected management employees (the “supplemental benefit plans” and collectively with the retirement plan, the “pension plans”). The supplemental benefit plans provide for benefits that supplement those provided by the retirement plan. The obligations under these supplemental benefit plans are included in the pension benefit obligation calculations below. The investments held in trust for the supplemental benefit plans of $53 million and $53 million at December 31, 2018 and 2017 , respectively, are not included in the plan asset amounts presented below, but are included in other assets on our consolidated statements of financial position . For the years ended December 31, 2018 , 2017 and 2016 , we contributed $3 million , $14 million and $5 million , respectively, to these supplemental benefit plans.

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

Asset Category	2018			2017
Fixed income securities	48.6	%		50.2	%
Equity securities	51.4	%		49.8	%
Total	100.0	%		100.0	%

Net periodic benefit cost for the pension plans during 2018 , 2017 and 2016 was as follows by component:

(In millions)	2018				2017				2016
Service cost	$	7			$	6			$	6
Interest cost	4				4				4
Expected return on plan assets	(5		)		(4		)		(4		)
Amortization of unrecognized loss	1				1				4
Net pension cost	$	7			$	7			$	10

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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, 2018 and 2017 :

(In millions)	2018				2017
Change in Benefit Obligation:
Beginning projected benefit obligation	$	(127	)		$	(116	)
Service cost	(7		)		(6		)
Interest cost	(4		)		(4		)
Actuarial net gain (loss)	9				(7		)
Benefits paid	6				6
Ending projected benefit obligation	(123		)		(127		)
Change in Plan Assets:
Beginning plan assets at fair value	75				64
Actual return on plan assets	(3		)		9
Employer contributions	4				4
Benefits paid	(3		)		(2		)
Ending plan assets at fair value	73				75
Funded status, underfunded	$	(50	)		$	(52	)
Accumulated benefit obligation:
Retirement plan	$	(67	)		$	(67	)
Supplemental benefit plans	(52		)		(56		)
Total accumulated benefit obligation	$	(119	)		$	(123	)
Amounts recorded as:
Funded Status:
Accrued pension liabilities	$	(50	)		$	(54	)
Other non-current assets	4				6
Other current liabilities	(4		)		(4		)
Total	$	(50	)		$	(52	)
Unrecognized Amounts in Non-current Regulatory Assets:
Net actuarial loss	$	24			$	26
Total	$	24			$	26

The unrecognized amounts that otherwise would have been charged and/or credited to AOCI in accordance with the FASB guidance on accounting for retirement benefits are recorded as a regulatory asset on our consolidated statements of financial position as discussed in Note 7 . The amounts recorded as a regulatory asset represent a net periodic benefit cost to be recognized in our operating income in future periods.

Actuarial assumptions used to determine the benefit obligation for the pension plans at December 31, 2018 , 2017 and 2016 are as follows:

	2018		2017		2016
Weighted average discount rate	4.28%		3.57%		4.00%
Annual rate of salary increases	4.00%		4.00%		4.00%

Actuarial assumptions used to determine the benefit cost for the pension plans for the years ended December 31, 2018 , 2017 and 2016 are as follows:

	2018		2017		2016
Weighted average discount rate — service cost	3.70%		4.20%		4.46%
Weighted average discount rate — interest cost	3.26%		3.45%		3.62%
Annual rate of salary increases	4.00%		4.00%		4.00%
Expected long-term rate of return on plan assets	6.40%		6.20%		6.40%

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At December 31, 2018 , 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)
2019	$	7
2020	7
2021	8
2022	8
2023	9
2024 through 2028	53

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, 2018 and 2017 , there were no transfers between levels.

The fair value measurement of the retirement plan assets as of December 31, 2018 , was as follows:

	Fair Value Measurements at Reporting Date Using
	Quoted Prices in				Significant				Significant
	Active Markets for				Other Observable				Unobservable
	Identical Assets				Inputs				Inputs
(In millions)	(Level 1)				(Level 2)				(Level 3)
Financial assets measured on a recurring basis:
Mutual funds — U.S. equity securities	$	30			$	—			$	—
Mutual funds — international equity securities	7				—				—
Mutual funds — fixed income securities	36				—				—
Total	$	73			$	—			$	—

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

	Fair Value Measurements at Reporting Date Using
	Quoted Prices in				Significant				Significant
	Active Markets for				Other Observable				Unobservable
	Identical Assets				Inputs				Inputs
(In millions)	(Level 1)				(Level 2)				(Level 3)
Financial assets measured on a recurring basis:
Mutual funds — U.S. equity securities	$	30			$	—			$	—
Mutual funds — international equity securities	7				—				—
Mutual funds — fixed income securities	38				—				—
Total	$	75			$	—			$	—

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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.

Other Postretirement Benefits

We provide certain postretirement health care, dental and life insurance benefits for eligible employees. We contributed $9 million , $8 million and $7 million to the postretirement benefit plan in 2018 , 2017 and 2016 , respectively. We expect to contribute $8 million to the postretirement benefit plan in 2019 .

The plan assets of the postretirement benefit plan consisted of the following assets by category:

Asset Category	2018			2017
Fixed income securities	48.4	%		50.1	%
Equity securities	51.6	%		49.9	%
Total	100.0	%		100.0	%

Net postretirement benefit plan cost for the postretirement benefit plan for 2018 , 2017 and 2016 was as follows by component:

(In millions)	2018				2017				2016
Service cost	$	10			$	8			$	7
Interest cost	3				3				3
Expected return on plan assets	(3		)		(2		)		(2		)
Net postretirement cost	$	10			$	9			$	8

The following table reconciles the obligations, assets and funded status of the plan as well as the amounts recognized as accrued postretirement liability in the consolidated statements of financial position as of December 31, 2018 and 2017 :

(In millions)	2018				2017
Change in Benefit Obligation:
Beginning accumulated postretirement obligation	$	(86	)		$	(68	)
Service cost	(10		)		(8		)
Interest cost	(3		)		(3		)
Actuarial net gain (loss)	8				(8		)
Benefits paid	1				1
Ending accumulated postretirement obligation	(90		)		(86		)
Change in Plan Assets:
Beginning plan assets at fair value	66				52
Actual return on plan assets	(2		)		7
Employer contributions	9				8
Benefits paid	(1		)		(1		)
Ending plan assets at fair value	72				66
Funded status, underfunded	$	(18	)		$	(20	)
Amounts recorded as:
Funded Status:
Accrued postretirement liabilities	$	(18	)		$	(20	)
Total	$	(18	)		$	(20	)
Unrecognized Amounts in Non-current Regulatory Assets:
Net actuarial loss	$	1			$	4
Total	$	1			$	4

The unrecognized amounts that otherwise would have been charged and/or credited to AOCI in accordance with the FASB guidance on accounting for retirement benefits are recorded as a regulatory asset on our consolidated statements of financial position as discussed in Note 7 . The amounts recorded as a regulatory asset represent a net periodic benefit cost to be recognized in our operating income in future periods. Our measurement of the accumulated

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postretirement benefit obligation as of December 31, 2018 and 2017 does not reflect the potential receipt of any subsidies under the Medicare Prescription Drug, Improvement and Modernization Act of 2003.

Net actuarial gains and losses for the years ended December 31, 2018 and 2017 are the result of changes in the discount rate and actual returns on plan assets.

Actuarial assumptions used to determine the benefit obligation for the postretirement benefit plan at December 31, 2018 , 2017 and 2016 are as follows:

	2018		2017		2016
Discount rate	4.47%		3.75%		4.28%
Annual rate of salary increases	4.00%		4.00%		4.00%
Health care cost trend rate	6.50%		6.75%		7.00%
Ultimate health care cost trend rate	5.00%		5.00%		5.00%
Year that the ultimate trend rate is reached	2025		2025		2022
Annual rate of increase in dental benefit costs	4.50%		4.50%		5.00%

Actuarial assumptions used to determine the benefit cost for the postretirement benefit plan for the years ended December 31, 2018 , 2017 and 2016 are as follows:

	2018		2017		2016
Discount rate — service cost	3.80%		4.35%		4.72%
Discount rate — interest cost	3.58%		3.98%		4.21%
Annual rate of salary increases	4.00%		4.00%		4.00%
Health care cost trend rate	6.75%		7.00%		7.15%
Ultimate health care cost trend rate	5.00%		5.00%		5.00%
Year that the ultimate trend rate is reached	2025		2022		2022
Expected long-term rate of return on plan assets	4.90%		4.70%		4.80%

At December 31, 2018 , the projected benefit payments for the postretirement benefit plan calculated using the same assumptions as those used to calculate the benefit obligations described above are as follows:

(In millions)
2019	$	1
2020	1
2021	2
2022	2
2023	2
2024 through 2028	19

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point increase or decrease in assumed health care cost trend rates would have the following effects on service and interest cost for 2018 and the postretirement benefit obligation at December 31, 2018 :

	One-Percentage-				One-Percentage-
(In millions)	Point Increase				Point Decrease
Effect on total of service and interest cost	$	5			$	(3	)
Effect on postretirement benefit obligation	21				(15		)

Investment Objectives and Fair Value Measurement

The general investment objectives of the postretirement benefit 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 other postretirement benefit plan, including

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derivatives, but our exposure to derivatives currently is not material. We intend that the long-term capital growth of the postretirement benefit 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 target allocations of the postretirement benefit plan investments as well as consider historical 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, 2018 and 2017 , there were no transfers between levels.

The fair value measurement of the postretirement benefit plan assets as of December 31, 2018 , was as follows:

	Fair Value Measurements at Reporting Date Using
	Quoted Prices in				Significant				Significant
	Active Markets for				Other Observable				Unobservable
	Identical Assets				Inputs				Inputs
(In millions)	(Level 1)				(Level 2)				(Level 3)
Financial assets measured on a recurring basis:
Mutual funds — U.S. equity securities	$	36			$	—			$	—
Mutual funds — international equity securities	1				—				—
Mutual funds — fixed income securities	35				—				—
Total	$	72			$	—			$	—

The fair value measurement of the postretirement benefit plan assets as of December 31, 2017 , was as follows:

	Fair Value Measurements at Reporting Date Using
	Quoted Prices in				Significant				Significant
	Active Markets for				Other Observable				Unobservable
	Identical Assets				Inputs				Inputs
(In millions)	(Level 1)				(Level 2)				(Level 3)
Financial assets measured on a recurring basis:
Mutual funds — U.S. equity securities	$	31			$	—			$	—
Mutual funds — international equity securities	2				—				—
Mutual funds — fixed income securities	33				—				—
Total	$	66			$	—			$	—

Our mutual fund investments consist primarily of publicly traded mutual funds and are recorded at fair value based on observable trades for identical securities in an active market.

Defined Contribution Plan

We also sponsor a defined contribution retirement savings plan. Participation in this plan is available to substantially all employees. We match employee contributions up to certain predefined limits based upon eligible compensation and the employee’s contribution rate. The cost of this plan was $5 million , $5 million and $7 million in 2018 , 2017 and 2016 , respectively.

13 .     FAIR VALUE MEASUREMENTS

The measurement of fair value is based on a three-tier hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. Changes in economic conditions or model-based valuation techniques may require the transfer of financial instruments from one fair value level to another. In such instances, the transfer is reported at the beginning of the reporting period. For the years ended December 31, 2018 and 2017 , there were no transfers between levels.

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

	Fair Value Measurements at Reporting Date Using
	Quoted Prices in Active Markets for Identical Assets				Significant Other Observable Inputs				Significant Unobservable Inputs
(In millions)	(Level 1)				(Level 2)				(Level 3)
Financial assets measured on a recurring basis:
Cash equivalents	$	1			$	—			$	—
Mutual funds — fixed income securities	49				—				—
Mutual funds — equity securities	5				—				—
Total	$	55			$	—			$	—

Our assets measured at fair value subject to the three-tier hierarchy at December 31, 2017 , were as follows:

	Fair Value Measurements at Reporting Date Using
	Quoted Prices in Active Markets for Identical Assets				Significant Other Observable Inputs				Significant Unobservable Inputs
(In millions)	(Level 1)				(Level 2)				(Level 3)
Financial assets measured on a recurring basis:
Cash equivalents	$	1			$	—			$	—
Mutual funds — fixed income securities	52				—				—
Mutual funds — equity securities	1				—				—
Total	$	54			$	—			$	—

As of December 31, 2018 and 2017 , we held certain assets that are required to be measured at fair value on a recurring basis. The assets included in the table consist of investments recorded within cash and cash equivalents and other long-term assets, including investments held in a trust associated with our supplemental benefit plans described in Note 12 . The mutual funds we own are publicly traded and are recorded at fair value based on observable trades for identical securities in an active market. Changes in the observed trading prices and liquidity of money market funds are monitored as additional support for determining fair value. Beginning on January 1, 2018, gains and losses for all mutual fund investments are recorded in earnings. Previously, gains and losses on available-for-sale investments were recorded in AOCI.

We also held non-financial assets that are required to be measured at fair value on a non-recurring basis. These consist of goodwill and intangible assets. We did not record any impairment charges on long-lived assets and no other significant events occurred requiring non-financial assets and liabilities to be measured at fair value (subsequent to initial recognition) during the years ended December 31, 2018 and 2017 . For additional information on our goodwill and intangible assets refer to Note 9 .

Fair Value of Financial Assets and Liabilities

Fixed Rate Debt

Based on the borrowing rates obtained from third party lending institutions currently available for bank loans with similar terms and average maturities from active markets, the fair value of our consolidated long-term debt and debt maturing within one year, excluding revolving and term loan credit agreements and commercial paper, was $5,186 million  and $5,192 million at December 31, 2018 and 2017 , respectively. These fair values represent Level 2 under the three-tier hierarchy described above. The total book value of our consolidated long-term debt and debt maturing within one year, net of discount and deferred financing fees and excluding revolving and term loan credit agreements and commercial paper, was $5,130 million and $4,830 million at December 31, 2018 and 2017 , respectively.

Revolving and Term Loan Credit Agreements

At December 31, 2018 and 2017 , we had a consolidated total of $208 million and $271 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

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obtained from third party lending institutions. These fair values represent Level 2 under the three-tier hierarchy described above.

Other Financial Instruments

The carrying value of other financial instruments included in current assets and current liabilities, including cash and cash equivalents, special deposits and commercial paper, approximates their fair value due to the short-term nature of these instruments.

14 .     STOCKHOLDER'S EQUITY

Accumulated Other Comprehensive Income

The following table provides the components of changes in AOCI for the years ended December 31, 2018 , 2017 and 2016 :

	Year Ended December 31,
(In millions)	2018				2017				2016
Balance at the beginning of period	$	2			$	2			$	4
Reclassification of deferred tax effects on interest rate cash flow hedges stranded in AOCI, subject to the TCJA, into retained earnings	1				—				—
Other Comprehensive Income
Derivative Instruments
Reclassification of net loss relating to interest rate cash flow hedges from AOCI to earnings (net of tax of less than $1 for the year ended December 31, 2018 and $1 for the years ended December 31, 2017 and 2016, respectively) (a)	1				1				1
Loss on interest rate swaps relating to interest rate cash flow hedges (net of tax of $1 and $2 for the years ended December 31, 2017 and 2016, respectively)	—				(1		)		(3		)
Total other comprehensive income (loss), net of tax	1				—				(2		)
Balance at the end of period	$	4			$	2			$	2

____________________________

(a)	The reclassification of the net loss relating to interest rate cash flow hedges is reported in interest expense on a pre-tax basis.

The amount of net loss relating to interest rate cash flow hedges to be reclassified from AOCI to earnings for the 12-month period ending December 31, 2019 is expected to be approximately $1 million (net of tax of less than $1 million ). The reclassification is reported in interest expense on a pre-tax basis.

15 .     SHARE-BASED COMPENSATION AND EMPLOYEE SHARE PURCHASE PLAN

We recorded share-based compensation in 2018 , 2017 and 2016 as follows:

(In millions)	2018 (a)				2017 (a)				2016
Operation and maintenance expenses	$	1			$	1			$	2
General and administrative expenses (b)	7				3				52
Amounts capitalized to property, plant and equipment	3				1				5
Total share-based compensation	$	11			$	5			$	59
Total tax benefit recognized in the consolidated statements of comprehensive income	$	4			$	1			$	49

____________________________

(a)	All amounts for the years ended December 31, 2018 and 2017 relate to the 2017 Omnibus Plan; see below for further discussion on the 2017 Omnibus Plan.

(b)	Amount for the year ended December 31, 2016 includes the expense recognized due to the accelerated vesting of the share-based awards upon completion of the Merger as described below.

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2017 Omnibus Plan

Under the 2017 Omnibus Plan, we may grant long-term incentive awards of PBUs and SBUs to employees, including executive officers, of ITC Holdings and its subsidiaries. Each PBU and SBU granted will be valued based on one share of Fortis common stock traded on the Toronto Stock Exchange, converted to U.S. dollars and settled only in cash. The awards vest on the date specified in a particular grant agreement, provided the service and performance criteria, as applicable, are satisfied.

Performance-Based Units

The PBUs are classified as liability awards based on the cash settlement feature. The PBUs are measured at fair value at the end of each reporting period, which will fluctuate based on the price of Fortis common stock and the level of achievement of the financial performance criteria, including a market condition and a performance condition. The payout may range from 0% - 200% of the target award, depending on actual performance relative to the performance criteria. The PBUs earn dividend equivalents which are also re-measured consistent with the target award and settled in cash at the end of the vesting period. The granted awards and related dividend equivalents have no shareholder rights. PBUs that were granted pursuant to the 2017 Omnibus Plan generally vest on the third December 31 ^st following the grant date, provided the service and performance criteria are satisfied and will be settled during the subsequent quarter.

The following table shows the changes in PBUs during the year ended December 31, 2018 :

	Number of
	Performance
	Based Units
PBUs at December 31, 2017	334,386
Granted	318,781
Forfeited	(15,616	)
PBUs at December 31, 2018	637,551

The aggregate fair value of PBUs as of December 31, 2018 was $18 million . At December 31, 2018 , the total unrecognized compensation cost related to the PBUs is $11 million and the weighted average period over which that cost is expected to be recognized is 2 years .

Service-Based Units

The SBUs are classified as liability awards based on the cash settlement feature. The SBUs are measured at fair value at the end of each reporting period, which will fluctuate based on the price of Fortis common stock. The SBUs earn dividend equivalents which are also re-measured based on the price of Fortis common stock and settled in cash at the end of the vesting period. The granted awards and related dividend equivalents have no shareholder rights. SBUs that were granted pursuant to the 2017 Omnibus Plan generally vest on the third December 31 ^st following the grant date, provided the service criterion is satisfied and vested awards will be settled during the subsequent quarter.

The following table shows the changes in SBUs during the year ended December 31, 2018 :

	Number of
	Service
	Based Units
SBUs at December 31, 2017	257,769
Granted	247,745
Vested	(994	)
Forfeited	(15,617	)
SBUs at December 31, 2018	488,903

The aggregate fair value of SBUs as of December 31, 2018 is $17 million . At December 31, 2018 , the total unrecognized compensation cost related to the SBUs is $9 million and the weighted average period over which that cost is expected to be recognized is 2 years .

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2015 Long-Term Incentive Plan and Second Amended and Restated 2006 Long-Term Incentive Plan

Under the Merger Agreement, outstanding options to acquire common stock of ITC Holdings vested immediately prior to closing and were converted into the right to receive the difference between the Merger consideration and the exercise price of each option in cash, restricted stock vested immediately prior to closing and was converted into the right to receive the Merger consideration in cash and performance shares vested immediately prior to closing at the higher of target or actual performance through the effective time of the Merger and were converted into the right to receive the Merger consideration in cash. 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 . For the year ended December 31, 2016, we recognized approximately $41 million of expense due to the accelerated vesting of the share-based awards that occurred at the completion of the Merger. Refer to Note 1 for additional discussion regarding the Merger. As of December 31, 2018 and December 31, 2017 , there were no share-based payment awards outstanding under the plans that were in effect at or before the Merger.

Employee Share Purchase Plan

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

The ITC Holdings Employee Stock Purchase Plan in place prior to the Merger was a compensatory plan accounted for under the expense recognition provisions of the share-based payment accounting standards. Compensation cost was recorded based on the fair market value of the purchase options at the grant date, which corresponded to the first day of each purchase period, and was recognized over the purchase period. During 2016 employees purchased 40,219 shares, resulting in proceeds from the sale of our common stock of $1 million . The total share-based compensation cost for the Employee Stock Purchase Plan was less than $1 million for the year ended December 31, 2016.

16 .     JOINTLY OWNED UTILITY PLANT/COORDINATED SERVICES

Certain of our Regulated Operating Subsidiaries have agreements with other utilities for the joint ownership of substation assets and transmission lines. We account for these jointly owned assets by recording property, plant and equipment for our percentage of ownership interest. Various agreements provide the authority for construction of capital improvements and the operating costs associated with the substations and lines. Generally, each party is responsible for the capital, operation and maintenance and other costs of these jointly owned facilities based upon each participant’s undivided ownership interest, and each participant is responsible for providing its own financing. Our participating share of expenses associated with these jointly held assets are primarily recorded within operation and maintenance expenses on our consolidated statements of comprehensive income .

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We have investments in jointly owned utility assets as shown in the table below as of December 31, 2018 :

	Net Investments (a)
(In millions)	Substations				Lines				Other
ITCTransmission (b)	$	—			$	29			$	—
METC (c)	14				41				—
ITC Midwest (d)	37				37				5
ITC Great Plains (e)	10				23				—
Total	$	61			$	130			$	5

____________________________

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

(b)

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

(c)

METC has joint sharing of several assets within various substations with Consumers Energy, other municipal distribution systems and other generators. The rights, responsibilities and obligations for these jointly owned assets are documented in the Amended and Restated Distribution — Transmission Interconnection Agreement with Consumers Energy and in numerous interconnection facilities agreements with various municipalities and other generators. In addition, other municipal power agencies and cooperatives have an ownership interest in several METC 345 kV transmission lines. This ownership entitles these municipal power agencies and cooperatives to approximately 608 MW of network transmission service from the METC transmission system. As of December 31, 2018 , METC’s ownership percentages for jointly owned substation facilities and lines ranged from 6.3% to 92.0% and 1.0% to 41.9% , respectively.

(d)	ITC Midwest has joint sharing of several substations and transmission lines with various parties. As of December 31, 2018 , ITC Midwest had net investments in jointly owned substation assets under construction of $5 million . ITC Midwest’s ownership percentages for jointly owned substation facilities and lines ranged from 28.0% to 80.0% and 11.0% to 80.0% , respectively, as of December 31, 2018 .

(e)

In 2014, ITC Great Plains entered into a joint ownership agreement with an electric cooperative that has a 49.0% ownership interest in a transmission project. ITC Great Plains will construct and operate the project and the electric cooperative will be responsible for their ownership percentage of capital and operation and maintenance costs. As of December 31, 2018 , ITC Great Plains’ ownership percentage in the project was 51.0% .

17 .     RELATED PARTY TRANSACTIONS

Intercompany Receivables and Payables

ITC Holdings may incur charges from Fortis and other subsidiaries of Fortis that are not subsidiaries of ITC Holdings for general corporate expenses incurred. In addition, ITC Holdings may perform additional services for, or receive additional services from, Fortis and such subsidiaries. These transactions are in the normal course of business and payments for these services are settled through accounts receivable and accounts payable, as necessary. We had intercompany receivables from Fortis and such subsidiaries of less than $1 million at December 31, 2018 and December 31, 2017 and intercompany payables to Fortis and such subsidiaries of less than $1 million at December 31, 2018 and December 31, 2017 .

Related party charges for corporate expenses from Fortis and such subsidiaries are recorded in general and administrative expense. Such expense for both the years ended December 31, 2018 and 2017 for ITC Holdings were $8 million and less than $1 million during the year ended December 31, 2016 . Related party billings for services to Fortis and other subsidiaries recorded as an offset to general and administrative expenses for ITC Holdings were less than $1 million , $1 million and less than $1 million for the years ended December 31, 2018 , 2017 , and 2016 , respectively.

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Dividends

We paid dividends of $200 million, $300 million and $33 million during the years ended December 31, 2018 , 2017 and 2016 , respectively, to Investment Holdings. ITC Holdings also paid dividends of $73 million to Investment Holdings in January of 2019.

Merger

During the fourth quarter of 2016, we received $137 million from Investment Holdings for the cash settlement of the share-based awards that vested at the consummation of the Merger as described in Note 1 and Note 15 .

18 .     COMMITMENTS AND CONTINGENT LIABILITIES

Environmental Matters

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

Our assets and operations also involve the use of materials classified as hazardous, toxic or otherwise dangerous. Many of the properties that we own or operate have been used for many years and include older facilities and equipment that may be more likely than newer ones to contain or be made from such materials. Some of these properties include aboveground or underground storage tanks and associated piping. Some of them also include large electrical equipment filled with mineral oil, which may contain or previously have contained PCBs. Our facilities and equipment are often situated on or near property owned by others so that, if they are the source of contamination, others’ property may be affected. For example, aboveground and underground transmission lines sometimes traverse properties that we do not own and transmission assets that we own or operate are sometimes commingled at our transmission stations with distribution assets owned or operated by our transmission customers.

Some properties in which we have an ownership interest or at which we operate are, or are suspected of being, affected by environmental contamination. We are not aware of any pending or threatened claims against us with respect to environmental contamination relating to these properties, or of any investigation or remediation of contamination at these properties, that entail costs likely to materially affect us. Some facilities and properties are located near environmentally sensitive areas such as wetlands.

Litigation

We are involved in certain legal proceedings before various courts, governmental agencies and mediation panels concerning matters arising in the ordinary course of business. These proceedings include certain contract disputes, eminent domain and vegetation management activities, regulatory matters and pending judicial matters. We cannot predict the final disposition of such proceedings. We regularly review legal matters and record provisions for claims that are considered probable of loss.

Rate of Return on Equity Complaints

Two complaints have been filed with the FERC by combinations of consumer advocates, consumer groups, municipal parties and other parties challenging the base ROE in MISO. The complaints were filed with the FERC under Section 206 of the FPA requesting that the FERC find the MISO regional base ROE rate (the “base ROE”) for all MISO TO’s, including our MISO Regulated Operating Subsidiaries, to no longer be just and reasonable.

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A summary of the two complaints is as follows:

Complaint		15-Month Refund Period of Complaint (Beginning as of Complaint Filing Date)		Original Base ROE Authorized by the FERC at Time of Complaint Filing Date (a)		Base ROE Subsequently Authorized by the FERC for the Initial Complaint Period and also effective for the period from September 28, 2016 to current (a)		Reserve (Pre-Tax and Including Interest) as of December 31, 2018 (in millions)
Initial		11/12/2013 - 2/11/2015		12.38%		10.32%		$	—		(b)
Second		2/12/2015 - 5/11/2016		12.38%		N/A		151

____________________________

(a)	The ROE collected through the MISO Regulated Operating Subsidiaries’ rates during the period November 12, 2013 through September 27, 2016, a portion of which was later refunded to customers for the period of the Initial Complaint, consisted of a base ROE of 12.38% plus applicable incentive adders.

(b)	In 2017, $118 million , including interest, was refunded to customers of our MISO Regulated Operating Subsidiaries for the Initial Complaint based on the refund liability associated with the September 2016 Order.

Initial Complaint

On November 12, 2013, the Association of Businesses Advocating Tariff Equity, Coalition of MISO Transmission Customers, Illinois Industrial Energy Consumers, Indiana Industrial Energy Consumers, Inc., Minnesota Large Industrial Group and Wisconsin Industrial Energy Group (collectively, the “complainants”) filed the Initial Complaint with the FERC under Section 206 of the FPA requesting that the FERC find the then current 12.38% MISO base ROE for all MISO TOs, including our MISO Regulated Operating Subsidiaries, 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 and terminating the ROE adders approved for certain Regulated Operating Subsidiaries. The FERC set the base ROE for hearing and settlement procedures, while denying all other aspects of the Initial Complaint.

On September 28, 2016, the FERC issued the September 2016 Order that set the base ROE at 10.32% with a maximum ROE of 11.35% , effective for the period from November 12, 2013 through February 11, 2015. Additionally, the base ROE established by the September 2016 Order was to be used prospectively from the date of that order until a new approved base ROE was established by the FERC. The September 2016 Order required all MISO TOs, including our MISO Regulated Operating Subsidiaries, to provide refunds, which were completed in 2017. On October 28, 2016, the MISO TOs, including our MISO Regulated Operating Subsidiaries, filed a request with the FERC for rehearing of the September 2016 Order regarding the short-term growth projections in the two-step DCF analysis.

Second Complaint

On February 12, 2015, the Second Complaint was filed with the FERC under Section 206 of the FPA by Arkansas Electric Cooperative Corporation, Mississippi Delta Energy Agency, Clarksdale Public Utilities Commission, Public Service Commission of Yazoo City and Hoosier Energy Rural Electric Cooperative, Inc., seeking a FERC order to reduce the base ROE used in the formula transmission rates of our MISO Regulated Operating Subsidiaries to 8.67% , with an effective date of February 12, 2015.

On June 30, 2016, the presiding ALJ issued an initial decision that recommended a base ROE of 9.70% for the refund period from February 12, 2015 through May 11, 2016, with a maximum ROE of 10.68% , which also would be applicable going forward from the date of a final FERC order. On September 29, 2017, certain MISO transmission owners, including our MISO Regulated Operating Subsidiaries, filed a motion for the FERC to dismiss the Second Complaint. As of December 31, 2018, we had recorded an aggregate estimated current regulatory liability in the consolidated statements of financial position of $151 million for the Second Complaint.

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The recognition of the obligations associated with the complaints resulted in the following impacts:

	Year Ended December 31, 2018
(In millions)	2018				2017				2016
Revenue (increase) reduction	$	(1	)		$	—			$	80
Interest expense increase	7				6				10
Estimated net income reduction (a)	4				3				55

____________________________

(a)	Includes an effect on net income of $27 million for the year ended December 31, 2016 for revenue initially recognized in 2015, 2014 and 2013.

Prior to the filing of the MISO ROE complaints, complaints were filed with the FERC regarding the regional base ROE rate for ISO New England TOs. In resolving these complaints, the FERC adopted a methodology for establishing base ROE rates based on a two-step DCF analysis. This methodology provided the precedent for the FERC ruling on the Initial Complaint and the ALJ initial decision on the Second Complaint for our MISO Regulated Operating Subsidiaries. In April 2017, the D.C. Circuit Court vacated the precedent-setting FERC orders that established and applied the two-step DCF methodology for the determination of base ROE. The court remanded the orders to the FERC for further justification of its establishment of the new base ROE for the ISO New England TOs. On October 16, 2018, in the New England matters, the FERC issued an order on remand which proposes a new methodology for 1) determining when an existing ROE is no longer just and reasonable; and 2) setting a new just and reasonable ROE if an existing ROE has been found not to be just and reasonable. The FERC established a paper hearing on how the proposed new methodology should apply to the ISO New England TOs ROE complaint proceedings. The FERC issued a similar order, the November 2018 Order, in the MISO TO base ROE complaint proceedings establishing a paper hearing on the application of the proposed new methodology to the proceedings pending before the FERC involving the MISO TOs’ ROE, including our MISO Regulated Operating Subsidiaries. Briefs in the New England proceedings were filed on January 11, 2019 and briefs in the MISO proceedings were filed on February 13, 2019. Reply briefs for both the MISO and New England matters are due to be filed during the first half of 2019.

The November 2018 Order included illustrative calculations for the ROE that may be established for the Initial Complaint, using the FERC's proposed methodology with financial data from the proceedings related to that complaint. If the results of these illustrative calculations are confirmed in a final FERC order, then the application of the base ROE and the maximum ROE would not have a significant adverse impact on our financial condition, results of operations and cash flows.

Although the November 2018 Order provided illustrative calculations, the FERC stated that these calculations are merely preliminary. The FERC’s preliminary calculations are not binding and could change, as significant changes to the methodology by the FERC are possible as a result of the paper hearing process. Until there is more certainty around the ultimate resolution of these matters, we cannot reasonably update an estimated range of gain or loss for any of the complaint proceedings or estimate a range of gain or loss for the period subsequent to the end of the Second Complaint refund period. The November 2018 Order and our response to the order through briefs filed on February 13, 2019 do not provide a reasonable basis for a change to the reserve or recognized ROEs for any of the complaint refund periods nor all subsequent periods, and we believe that the risk of additional material loss beyond amounts already accrued is remote.

Our MISO Regulated Operating Subsidiaries currently record revenues at the base ROE of 10.32% established in the September 2016 Order on the Initial Complaint plus applicable incentive adders. See Note 6 to the consolidated financial statements for a summary of incentive adders for transmission rates.

As of December 31, 2018, our MISO Regulated Operating Subsidiaries had a total of approximately $4 billion of equity in their collective capital structures for ratemaking purposes. Based on this level of aggregate equity, we estimate that each 10 basis point change in the authorized ROE would impact annual consolidated net income by approximately $4 million .

Development Projects

We are pursuing strategic development projects that may result in payments to developers that are contingent on the projects reaching certain milestones indicating that the projects are financially viable. We believe it is reasonably possible that we will be required to make these contingent development payments up to a maximum

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amount of $125 million for the period from 2019 through 2022 . In the event it becomes probable that we will make these payments, we would recognize the liability and the corresponding intangible asset or expense as appropriate.

Purchase Obligations and Leases

At December 31, 2018 , we had purchase obligations of $49 million representing commitments for materials, services and equipment that had not been received as of December 31, 2018 , primarily for construction and maintenance projects for which we have an executed contract. Of these purchase obligations, $48 million is expected to be paid in 2019 , with the majority of the items related to materials and equipment that have long production lead times.

We have operating leases for office space, equipment and storage facilities. We recognize expenses relating to our operating lease obligations on a straight-line basis over the term of the lease. We recognized rent expense of $1 million for each of the years ended December 31, 2018 , 2017 and 2016 recorded in general and administrative expenses as well as operation and maintenance expenses. These amounts and the amounts in the table below do not include any expense or payments to be made under the METC Easement Agreement described below under “Other Commitments — METC — Amended and Restated Easement Agreement with Consumers Energy.”

Future minimum lease payments under the leases at December 31, 2018 are:

(In millions)
2019	$	1
2020	1
2021	1
2022	—
2023 and thereafter	1
Total minimum lease payments	$	4

Other Commitments

METC

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

Amended and Restated Easement Agreement. Under the Easement Agreement, Consumers Energy provides METC with an easement to the land on which a majority of METC’s transmission towers, poles, lines and other transmission facilities used to transmit electricity for Consumers Energy and others are located. METC pays Consumers Energy $10 million in annual rent per year for the easement and also pays for any rentals, property, taxes, and other fees related to the property covered by the Easement Agreement. Payments to Consumers Energy under the Easement Agreement are charged to operation and maintenance expenses.

ITC Midwest

Operations Services Agreement For 34.5 kV Transmission Facilities. ITC Midwest and IP&L entered into the OSA under which IP&L performs certain operations functions for ITC Midwest’s 34.5 kV transmission system on behalf of ITC Midwest. The OSA provides that when ITC Midwest upgrades 34.5 kV facilities to higher operating voltages it may notify IP&L of the change and the OSA is no longer applicable to those facilities.

ITC Great Plains

Amended and Restated Maintenance Agreement. Mid-Kansas and ITC Great Plains have entered into the Mid-Kansas Agreement pursuant to which Mid-Kansas has agreed to perform various field operations and maintenance services related to certain ITC Great Plains assets.

Concentration of Credit Risk

Our credit risk is primarily with DTE Electric, Consumers Energy and IP&L, which were responsible for approximately 21.4% , 23.1% and 26.6% , respectively, or $248 million , $269 million and $309 million , respectively,

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of our consolidated billed revenues for the year ended December 31, 2018 . These percentages and amounts of total billed revenues of DTE Electric, Consumers Energy and IP&L include the collection of 2016 revenue accruals and deferrals and exclude any amounts for the 2018 revenue accruals and deferrals that were included in our 2018 operating revenues but will not be billed to our customers until 2020 . Under DTE Electric’s and Consumers Energy’s current rate structure, DTE Electric and Consumers Energy include in their retail rates the actual cost of transmission services provided by ITCTransmission and METC, respectively, in their billings to their customers, effectively passing through to end-use consumers the total cost of transmission service. IP&L currently includes in their retail rates an allowance for transmission services provided by ITC Midwest in their billings to their customers. However, any financial difficulties experienced by DTE Electric, Consumers Energy or IP&L may affect their ability to make payments for transmission service to ITCTransmission, METC, and ITC Midwest, which could negatively impact our business. MISO, as our MISO Regulated Operating Subsidiaries’ billing agent, bills DTE Electric, Consumers Energy, IP&L and other customers on a monthly basis and collects fees for the use of the MISO Regulated Operating Subsidiaries’ transmission systems. SPP is the billing agent for ITC Great Plains and bills transmission customers for the use of ITC Great Plains transmission systems. MISO and SPP have implemented strict credit policies for its members’ customers, which include customers using our transmission systems. Specifically, MISO and SPP require a letter of credit or cash deposit equal to the credit exposure, which is determined by a credit scoring model and other factors, from any customer using a member’s transmission system.

The financial results of ITC Interconnection are currently not material to our consolidated financial statements, including billed revenues.

19 .     SUPPLEMENTAL FINANCIAL INFORMATION

Reconciliation of Cash, Cash Equivalents and Restricted Cash

The following table provides a reconciliation of cash, cash equivalents and restricted cash reported on the consolidated statements of financial position that sum to the total of the same such amounts shown in the consolidated statements of cash flows:

	December 31,
(In millions)	2018				2017				2016				2015
Cash and cash equivalents	$	6			$	66			$	8			$	14
Restricted cash included in:
Other non-current assets	4				2				3				1
Total cash, cash equivalents and restricted cash	$	10			$	68			$	11			$	15

Restricted cash included in other non-current assets primarily represents cash on deposit to pay for vegetation management, land easements and land purchases for the purpose of transmission line construction.

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Supplementary Cash Flow Information

The following table presents certain supplementary cash flows information for the years ended December 31, 2018 , 2017 and 2016 :

	Year Ended December 31, 2018
(In millions)	2018				2017				2016
Supplementary cash flows information:
Interest paid (net of interest capitalized) (a)	$	223			$	213			$	190
Income taxes paid	—				—				23
Income tax refunds received (b)	13				1				129
Supplementary non-cash investing and financing activities:
Additions to property, plant and equipment and other long-lived assets (c)	94				87				93
Allowance for equity funds used during construction	33				33				35

____________________________

(a)	Amount for the year ended December 31, 2017 includes $9 million of interest paid associated with the Initial Complaint. See Note 18 for information on the Initial Complaint.

(b)	Amount for the year ended December 31, 2016 includes the income tax refund of $128 million received from the IRS in August 2016, which resulted from the election of bonus depreciation.

(c)	Amounts consist of current and accrued liabilities for construction, labor, materials and other costs that have not been included in investing activities. These amounts have not been paid for as of December 31, 2018 , 2017 or 2016 , 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 consolidated statements of comprehensive income. Cash retained as a result of those excess tax benefits is presented in the consolidated statements of cash flows as cash inflows from operating activities.

20 .     SEGMENT INFORMATION

We identify reportable segments based on the criteria set forth by the FASB regarding disclosures about segments of an enterprise, including the regulatory environment of our subsidiaries and the business activities performed to earn revenues and incur expenses. During the second quarter of 2016, ITC Interconnection became a transmission owner in the FERC-approved RTO, PJM Interconnection. As a result, the newly regulated transmission business at ITC Interconnection is included in the Regulated Operating Subsidiaries segment as of June 1, 2016.

Regulated Operating Subsidiaries

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

ITC Holdings and Other

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

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	Regulated
	Operating				ITC Holdings				Reconciliations/
2018	Subsidiaries				and Other				Eliminations				Total
(In millions)
Operating revenues	$	1,185			$	—			$	(29	)		$	1,156
Depreciation and amortization	179				1				—				180
Interest expense, net	110				114				—				224
Income (loss) before income taxes	585				(144		)		—				441
Income tax provision (benefit)	148				(37		)		—				111
Net income	437				330				(437		)		330
Property, plant and equipment, net	7,901				9				—				7,910
Goodwill	950				—				—				950
Total assets (a)	9,224				4,977				(4,872		)		9,329
Capital expenditures	773				—				(4		)		769

	Regulated
	Operating				ITC Holdings				Reconciliations/
2017	Subsidiaries				and Other				Eliminations				Total
(In millions)
Operating revenues	$	1,241			$	—			$	(30	)		$	1,211
Depreciation and amortization	168				1				—				169
Interest expense, net	104				120				—				224
Income (loss) before income taxes	664				(149		)		—				515
Income tax provision (benefit)	207				(11		)		—				196
Net income	457				319				(457		)		319
Property, plant and equipment, net	7,299				10				—				7,309
Goodwill	950				—				—				950
Total assets (a)	8,688				4,799				(4,664		)		8,823
Capital expenditures	761				—				(6		)		755

	Regulated
	Operating				ITC Holdings				Reconciliations/
2016	Subsidiaries (b)				and Other				Eliminations				Total
(In millions)
Operating revenues	$	1,140			$	1			$	(16	)		$	1,125
Depreciation and amortization	157				1				—				158
Interest expense, net	99				112				—				211
Income (loss) before income taxes	597				(254		)		—				343
Income tax provision (benefit)	227				(130		)		—				97
Net income	371				246				(371		)		246
Property, plant and equipment, net	6,687				11				—				6,698
Goodwill	950				—				—				950
Total assets (a)	8,162				4,503				(4,442		)		8,223
Capital expenditures	758				—				(8		)		750

____________________________

(a)	Reconciliation of total assets results primarily from differences in the netting of deferred tax assets and liabilities in our segments as compared to the classification in our consolidated statements of financial position.

(b)	Amounts include the results of operations and capital expenditures from ITC Interconnection for the period June 1, 2016 through December 31, 2016.

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21 .     SUPPLEMENTARY QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

	First				Second				Third				Fourth
(In millions)	Quarter				Quarter				Quarter				Quarter				Year
2018
Operating revenues	$	279			$	290			$	295			$	292			$	1,156
Operating income	154				163				163				155				635
Net income	82				79				89				80				330
2017
Operating revenues	$	298			$	303			$	299			$	311			$	1,211
Operating income	173				177				175				185				710
Net income	80				81				82				76				319

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ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.

None.

ITEM 9A.      CONTROLS AND PROCEDURES.

Management’s Report on Internal Control Over Financial Reporting is included in Item 8 of this Form 10-K.

Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to provide reasonable assurance that material information required to be disclosed in our reports that we file or submit under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required financial disclosure. In designing and evaluating the disclosure controls and procedures, management recognized that a control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, with a company have been detected.

As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 of the Exchange Act. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective, at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

There have been no changes in our internal control over financial reporting during the quarter ended December 31, 2018 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B.      OTHER INFORMATION.

None.

PART III

ITEM 10.      DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.

DIRECTORS

Our Bylaws provide for the election of directors at each annual meeting of shareholders. Each director serves until the next annual meeting and until his or her successor is elected and qualified, or until his or her resignation or removal.

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

Linda H. Apsey, 49. Ms. Apsey became President and Chief Executive Officer of the Company in November 2016 and was elected a director of the Company in January 2017. From May 2016 through January 2017, Ms. Apsey served as the Company’s Executive Vice President and Chief Business Unit Officer, where she was responsible for leading all aspects of the financial and operational performance of our five Regulated Operating Subsidiaries and the Company’s development. She had previously served as the Company’s Executive Vice President, Chief Business Unit Officer and President, ITC Michigan since February 2015 where she was responsible for leading all aspects of the financial and operational performance of the Company’s five Regulated Operating Subsidiaries and acting as the business unit head and president of the ITCTransmission and METC operating

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companies. Ms. Apsey served as Executive Vice President and Chief Business Officer of the Company from June 2007 until February 2015. In this role, Ms. Apsey was responsible for managing each of our Regulated Operating Subsidiaries and the necessary business support functions, including regulatory strategy, federal and state legislative affairs, community government affairs, human resources, and marketing and communications. Prior to this appointment, Ms. Apsey served as our Senior Vice President - Business Strategy and was responsible for managing regulatory affairs, policy development, internal and external communications, community affairs and human resource functions. Ms. Apsey was Vice President - Business Strategy from March 2003 until she was named Senior Vice President in February 2006. Prior to joining the Company, Ms. Apsey was the Manager of Transmission Policy and Business Planning at ITCTransmission for two years when it was a subsidiary of DTE Energy and was a supervisor in the regulatory affairs department of DTE Energy’s Detroit Edison subsidiary for two years. Ms. Apsey currently serves as a director of the Fortis utility subsidiary, FortisAlberta Inc.

Robert A. Elliott, 63. Mr. Elliott became a director of the Company in January 2017. Mr. Elliott has served as President and Owner of Elliott Accounting, an accounting, income tax and management advisory services organization in Tucson, Arizona, since 1983. He also serves as an Investment Advisor Representative for Greenberg Financial Group, a brokerage firm, a position in which he has served since 2001. Mr. Elliott is currently the Chairman of the Board of UNS Energy Corporation, a subsidiary of Fortis, and has been a board member of that company since 2014. Mr. Elliott currently serves on the board of directors of AAA CSAA Insurance and AAA Auto Club Partners and is the Chair of the board of directors of AAA Mountain West Group and has been a board member of that company since 2016. He previously served on the board of directors of AAA Arizona Inc. from 2007 to 2016 and was Lead Director of Unisource Energy Inc. from 2010 to 2014. The Board selected Mr. Elliott to serve as a director because of his accounting experience, his familiarity with Fortis subsidiary operations and his experience serving as a leader on other boards of directors.

Albert Ernst, 69. Mr. Ernst became a director of the Company in January 2017. Mr. Ernst was also a member of the ITC Holdings Board of Directors from August 2014 through the closing of the Merger in October 2016. Mr. Ernst is a retired member of the law firm of Dykema Gossett PLLC, where he also served as director of Dykema’s Energy Industry Group. His experience with companies in the public utility, energy, transmission, telecommunications and rural electric cooperative fields spans more than three decades. With Dykema, Mr. Ernst worked with leading energy clients including our subsidiaries, ITCTransmission and METC. He also served as a consultant on utility-related matters to the U.S. Department of Defense, the DOE and the General Services Administration. Mr. Ernst currently serves on the board of the Sarasota Jewish Housing Council and Foundation, the board of the Sarasota Jewish Federation and is the Chairman of the Sarasota Life and Legacy Project. The Board selected Mr. Ernst to serve as a director due to his lifelong career in the energy industry, as well as his invaluable experience with public utility and energy matters and decades of experience in the practice of law.

Rhys D. Evenden, 45. Mr. Evenden became a director of the Company in October 2016. Mr. Evenden is the Head of Infrastructure — North America, GIC and has served in this position since January 2014. In this role he heads the North American infrastructure team, which is responsible for acquisitions and asset management for a portfolio of power, utility, midstream and transportation assets. Prior to rejoining GIC in January 2014, Mr. Evenden was a Principal at QIC Global Infrastructure. From March 2007 until December 2011, he served as a Senior Vice President at GIC Special Investments (GICSI) in London. Mr. Evenden joined GICSI from BAA Limited, where he served as Head of Business Development for outside terminal businesses across BAA Limited’s airports. Mr. Evenden currently serves on the board of directors of Oncor Electric Delivery Company, Texas Transmission Holdings Company and Bronco Holdings LLC. He previously served on the board of Starwest Generation, Yorkshire Water and its parent Kelda Holdings and as an alternate director on the board of Thames Water. Mr. Evenden was appointed as a member of our Board of Directors by Eiffel.

James P. Laurito, 62. Mr. Laurito became a director of the Company in October 2016. Mr. Laurito has served as Fortis’ Executive Vice President, Business Development since April 2016. Previously, Mr. Laurito served as the President and Chief Executive Officer of Fortis’ Central Hudson Gas & Electric Corporation subsidiary from January 2010 to November 2014. Prior to joining Central Hudson, Mr. Laurito served as the President and Chief Executive Officer of both New York State Electric and Gas Corporation and Rochester Gas and Electric Corporation, subsidiaries of Avangrid, Inc. Mr. Laurito has been Chairman of the Hudson Valley Economic Development Corporation since January 1, 2015 and currently serves on the board of Fortis’ UNS Energy Corporation subsidiary.

Barry V. Perry, 54. Mr. Perry became a director of the Company in October 2016. Mr. Perry is President and Chief Executive Officer of Fortis and has served as such since January 2015. Prior to his current position at Fortis,

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Mr. Perry served as President from June 30, 2014 to December 31, 2014 and prior to that served as Vice President, Finance and Chief Financial Officer since 2004. Mr. Perry joined the Fortis organization in 2000 as Vice President, Finance and Chief Financial Officer of Newfoundland Power Inc. Mr. Perry currently serves as a director of the Fortis utility subsidiaries, FortisBC and UNS Energy Corporation.

Sandra E. Pierce, 60. Ms. Pierce became a director of the Company in January 2017. Ms. Pierce is Senior Executive Vice President, Private Client Group & Regional Banking Director and Chair of Michigan for Huntington National Bank. Ms. Pierce joined Huntington in 2016 after its merger with FirstMerit Corporation in 2016. While at FirstMerit, Ms. Pierce served as Vice Chairman of FirstMerit Corporation and Chairman and CEO of FirstMerit Michigan, from 2013 to 2016. Prior to joining FirstMerit, Ms. Pierce served as Midwest Regional Executive, President and CEO for Charter One Bank, Michigan, a division of RBS Citizens, N.A. from 2004 to 2012. Ms. Pierce currently serves as a board member of Barton Malow Enterprises, Penske Automotive Group and American Axle & Manufacturing, Inc. She also serves as the current chair of the Detroit Financial Advisory Board and the chair of the Henry Ford Health System. The Board selected Ms. Pierce to serve as a director due to her leadership experience and familiarity with the geographic region in which the Company operates and conducts business.

Kevin L. Prust, 63. Mr. Prust became a director of the Company in January 2017. Mr. Prust retired in 2014 as Executive Vice President and Chief Financial Officer of The Weitz Company, LLC, a large national and international construction firm, a position he held since joining the company in 2009. Prior to that, Mr. Prust was with McGladrey & Pullen LLP, a national CPA firm, from 1978 through 2008 serving in various positions and becoming partner in 1985. Mr. Prust served on the board of Mercy Medical Center, in Des Moines, Iowa from 2009 to 2018. In 2015 Mr. Prust served on the board of Stock Building Supply Holdings, Inc. until the company was acquired, and from 2009 to 2013 served on the board of Stark Bank Group and First American Bank. The Board selected Mr. Prust to serve as a director because of the expansive financial and accounting experience he obtained as a chief financial officer as well as his familiarity with the geographic region in which the Company operates and conducts business. The Board has determined that Mr. Prust is an “audit committee financial expert”, as that term is defined under SEC rules.

A. Douglas Rothwell, 62. Mr. Rothwell became a director of the Company in October 2017. Since 2005 Mr. Rothwell has served as President and CEO of Business Leaders for Michigan - a business roundtable of the state’s top 75 CEOs. From 2003 to 2005, Mr. Rothwell was the Executive Director of Worldwide Real Estate for General Motors where he managed their 400 million square foot global real estate portfolio. From 1993 to 2002, Mr. Rothwell was the President and Chief Executive Officer of the Michigan Economic Development Corporation, an organization he founded and directed to manage the state’s business development, innovation, tourism and community development programs. Mr. Rothwell currently chairs the Michigan Economic Development Corporation, chairs the American Center for Mobility, is chair-elect of the University of North Carolina at Chapel Hill’s Board of Visitors, and serves on the Board of Advisors for UNC athletics, and the management board of the Renaissance Venture Capital Fund. The Board selected Mr. Rothwell to serve as a director because of his vast experience working with business leaders in various industries to foster business development and growth and his familiarity and business contacts within the geographic region in which the Company operates and conducts business.

Thomas G. Stephens, 70.  Mr. Stephens became a director of the Company in January 2017. Mr. Stephens was also a member of the Board of Directors from November 2012 through the closing of the Merger in October 2016. Mr. Stephens retired in April 2012 from General Motors Company, a designer, manufacturer and marketer of vehicles and automobile parts, after 43 years with the company. Prior to his retirement, Mr. Stephens served as Vice Chairman and Chief Technology Officer. Mr. Stephens currently is Vice Chairman of the board of FIRST (For Inspiration and Recognition of Science and Technology in Michigan Robotics), Chairman of the Board of the Michigan Science Center and sits on the Board of Managers of Warehouse Technologies LLC and the board of directors of xF Technologies Inc. The Board selected Mr. Stephens to serve as a director because of his strong technical and engineering background as well as his experience and proven leadership capabilities assisting a large organization to achieve its business objectives.

Joseph L. Welch, 70. Mr. Welch has served as Chairman of the Board of Directors of the Company since May 2008 and as a director since 2003. He served as the Company’s President and Chief Executive Officer from 2003 until November 2016 and also served as the Company’s Treasurer from 2003 until 2009. As the founder of ITCTransmission, Mr. Welch has had overall responsibility for the Company’s vision, foundation and transformation into the first independently owned and operated electricity transmission company in the United States. Mr. Welch worked for Detroit Edison Company and other subsidiaries of DTE Energy from 1971 to 2003. During that time,

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he held positions of increasing responsibility in the electricity transmission, distribution, rates, load research, marketing and pricing areas, as well as regulatory affairs that included the development and implementation of regulatory strategies. Mr. Welch currently serves as a director of Fortis. The Board selected Mr. Welch to serve as a director because he previously served as the Company’s President and Chief Executive Officer and he possesses unparalleled expertise in the electric transmission business.

EXECUTIVE OFFICERS

Set forth below are the names, ages and titles of our current executive officers and a description of their business experience. Our executive officers serve as executive officers at the pleasure of the Board of Directors.

Linda H. Apsey, 49. Ms. Apsey’s background is described above under “Directors.”

Gretchen L. Holloway, 44. Ms. Holloway was named Senior Vice President and Chief Financial Officer in July 2017. Prior to this role, Ms. Holloway served as Vice President, Interim Chief Financial Officer and Treasurer, a position in which she served since October 2016. In her role, Ms. Holloway is responsible for the Company’s accounting, internal audit, treasury, financial planning and analysis, management reporting, risk management and tax functions. From May 2016 to October 2016, Ms. Holloway was Vice President and Treasurer and from November 2015 until May 2016, Ms. Holloway served as Vice President, Finance and Treasurer of the Company. In this role and her immediate past role, she was responsible for all treasury and corporate planning activities including cash management and as the Company’s liaison with the investment banking community and rating agencies. Ms. Holloway served from February 2015 to November 2015 as Vice President, Finance of the Company, where she was responsible for corporate finance activities including oversight of the budget and forecast processes and other financial analysis. Prior to that, Ms. Holloway served from June 2010 until February 2015 as Director, Special Projects & Investor Relations of the Company, where she was responsible for supporting the sourcing, evaluation and execution of mergers and acquisitions and implementing investor relations strategies and objectives. Prior to joining the Company in 2004, Ms. Holloway held various finance positions at CMS Energy Corporation for five years and before that, served as a financial consultant at Arthur Andersen for three years. Ms. Holloway currently serves as a member of the Finance & Audit Committee for the Children’s Hospital of Michigan Foundation.

Jon E. Jipping, 52. Jon E. Jipping has served as Executive Vice President and Chief Operating Officer since June 2007. In this position, Mr. Jipping is responsible for leading the Company’s five Regulated Operating Subsidiaries. Mr. Jipping is also responsible for transmission system planning, system operations, engineering, supply chain, field construction and maintenance, and information technology. Prior to this appointment, Mr. Jipping served as Senior Vice President - Engineering and was responsible for transmission system design, project engineering and asset management. Mr. Jipping joined the Company as Director of Engineering in March 2003, was appointed Vice President - Engineering in 2005 and was named Senior Vice President in February 2006. Prior to joining the Company, Mr. Jipping was with DTE Energy for thirteen years. He was Manager of Business Systems & Applications in DTE Energy’s Service Center Organization, responsible for implementation and management of business applications across the distribution business unit, and held positions of increasing responsibility in DTE Energy’s Transmission Operations and Transmission Planning department. Mr. Jipping currently serves on the board of Wataynikaneyap Power PM Inc., an entity owned by FortisOntario, Inc., a subsidiary of Fortis, which was created to develop and operate transmission to connect remote First Nation communities to the electrical grid in northwestern Ontario, Canada. He also serves as the Chair of the Advisory Board of the Michigan Technological University College of Engineering and as the Chair of the Board of the North American Transmission Forum.

Christine Mason Soneral, 46. Christine Mason Soneral was named Senior Vice President and General Counsel in April 2015 and served as Vice President and General Counsel from February 2015 through this appointment. As General Counsel, she is responsible for all corporate legal affairs and the leadership of our legal department. Prior to this role, Ms. Mason Soneral was Vice President and General Counsel-Utility Operations since 2007 and was responsible for legal matters connected with the operations, capital projects, contract, regulatory, property and litigation matters of the Company’s Regulated Operating Subsidiaries. Ms. Mason Soneral joined the Company in September 2007 from Dykema Gossett PLLC, a national law firm where she was a member. While in private practice at Dykema from 1998 through 2007, Ms. Mason Soneral represented clients before state and federal trial courts, appellate courts and regulatory agencies. In 2014, Ms. Mason Soneral was appointed to the board of Citizens Research Council, a privately funded, not-for-profit public affairs research organization. Ms. Mason Soneral also currently serves as a member of the Michigan State University College of Social Science's External Advisory Board and Women’s Leadership Institute.

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Daniel J. Oginsky, 45. Mr. Oginsky has served as Executive Vice President and Chief Administrative Officer since May 2016. In this role, he has responsibility for the Company’s regulatory, federal affairs, marketing and communications, human resources, strategic planning and enterprise planning process, state government affairs, and local community and government affairs functions. Mr. Oginsky served as Executive Vice President, U.S. Regulated Grid Development from February 2015 to May 2016. He was responsible for leading the Company’s growth and expansion through new investments in regulated electric transmission infrastructure across the United States. Mr. Oginsky joined as our Vice President and General Counsel in November 2004, served as Senior Vice President and General Counsel since May 2009 and was named Executive Vice President and General Counsel in May 2014. In these roles, Mr. Oginsky was responsible for the legal affairs of the Company and oversaw the legal department, which included the legal, corporate secretary, real estate, contract administration and corporate compliance functions. Mr. Oginsky also served as the Company’s Secretary from November 2004 until June 2007. Prior to joining the Company, Mr. Oginsky was an attorney in private practice for five years with various firms, where his practice focused primarily on representing ITCTransmission and other energy clients on regulatory, administrative litigation, transactional, property tax and legislative matters. Mr. Oginsky currently serves as a member of the Advisory Board of Belle Tire, Inc., President of North Manitou Light Keepers, Inc. and as a member of the Board of Visitors for James Madison College at Michigan State University.

Code of Conduct and Ethics

We have adopted a Code of Conduct and Ethics that applies to all of our directors, employees and executive officers, including our chief executive officer, chief financial officer and principal accounting officer. The Code of Conduct and Ethics, as currently in effect (together with any amendments that may be adopted from time to time), is available on our website at www.itc-holdings.com . To the extent required by the Code of Conduct and Ethics or by applicable law, we will post any amendments to the Code of Conduct and Ethics and any waivers that are required to be disclosed by the rules of the SEC on our website, within the required periods.

ITEM 11.      EXECUTIVE COMPENSATION.

COMPENSATION OF EXECUTIVE OFFICERS AND DIRECTORS

Compensation Discussion and Analysis

The following Compensation Discussion and Analysis describes the elements of compensation for our Chief Executive Officer (or “CEO”), our Chief Financial Officer and the three other most highly compensated executive officers who were serving as such at December 31, 2018 . We refer to these individuals collectively as the named executive officers or NEOs.

The Company’s named executive officers for 2018 were:

Name	Position
Linda H. Apsey	President and Chief Executive Officer
Gretchen L. Holloway	Senior Vice President and Chief Financial Officer
Jon E. Jipping	Executive Vice President and Chief Operating Officer
Daniel J. Oginsky	Executive Vice President and Chief Administrative Officer
Christine Mason Soneral	Senior Vice President and General Counsel

Executive Summary

The Governance and Human Resources Committee (the “Committee”) is responsible for determining the compensation of our NEOs and administering the plans in which the NEOs participate. The goals of our compensation system are to attract first-class executive talent in a competitive environment and to motivate and retain key employees who are crucial to our success by rewarding Company and individual performance that promotes long-term sustainable growth and increases shareholder value. The key components of our NEOs' compensation package include base salary, annual cash incentive bonuses, long-term equity incentives, as well as certain perquisites and other benefits. In determining the amount of NEO compensation, we consider competitive compensation practices of other utilities and similarly sized organizations, the executive's individual performance against objectives, the executive's responsibilities and expertise, and our performance in relation to annual goals that are designed to strengthen and enhance our value.

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The Committee made the following decisions with regard to executive compensation in 2018 :

•	Base salary increases . Base salary increases were provided to each of our NEOs in 2018 to reward individual performance and to remain competitive and aligned with market.

•

Annual cash incentive bonuses. The NEOs earned cash incentive bonuses for 2018 performance of approximately 154.8% of target. This was based on achieving 95% of the performance targets established under the annual corporate performance bonus plan in early 2018 and achievement of certain performance factors which resulted in a bonus multiplier of 1.63. See “Compensation Discussion and Analysis - Key Components of Our NEO Compensation Program - Annual Corporate Performance Bonus.”

•	Long-term equity incentives . We granted long-term equity incentive awards to our NEOs in March 2018. Total award opportunities were set as a percentage of base salary and delivered one-third in the form of SBUs and two-thirds in the form of PBUs.

Overview and Philosophy

The objectives of our compensation program are to attract first-class executive talent in a competitive environment and to motivate and retain key employees who are crucial to our success by rewarding Company and individual performance that promotes long-term sustainable growth and increases shareholder value by:

•	Performing best-in-class utility operations;

•	Improving reliability, reducing congestion, and facilitating access to generation resources; and

•	Utilizing our experience and skills to seek and identify opportunities to invest in needed transmission and to optimize the value of those investments.

Our compensation program is designed to motivate and reward individual and corporate performance. Our compensation philosophy is to:

•	Provide for flexibility in pay practices to recognize our unique position and growth proposition;

•	Use a market-based pay program aligned with pay-for-performance objectives;

•	Leverage incentives, where possible, and align long-term incentive awards with improvements in our financial performance and shareholder value;

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

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

Risk and Reward Balance

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

Following the process in which Fortis selected a third-party independent consultant to perform a review of executive compensation across its three U.S. subsidiaries, the Committee engaged FW Cook, an independent compensation consultant, to conduct a comprehensive compensation program risk assessment. In September 2018, FW Cook reviewed the attributes and structure of our executive compensation programs for the purpose of identifying potential sources of risk within the program design. The review covered plan design and administration/governance risk, corporate governance and investor relations risk and talent risk.

Based on a report from FW Cook concluding that the Company’s compensation programs do not create risks that are reasonably likely to have a material adverse impact on the Company, the Committee concluded that none of our compensation programs and features contain elements that create material risk to the Company. Risk mitigating factors with respect to the Company’s compensation programs included a market competitive pay mix, the linking of pay to performance through annual cash bonus and long-term equity incentive plans, caps on annual cash bonus and long-term equity incentive plan payouts, various performance measures that are both financially and operationally focused, a compensation recoupment policy, oversight by an independent committee of directors, regular review of NEO tally sheets and engagement of an independent compensation consultant.

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Benchmarking and Relationship of Compensation Elements

Benchmarking. We reviewed market competitive target pay levels from two distinct market samples, utility and general industry data, as reflected in published surveys. Pay Governance, the Committee’s independent advisor, compiled data for the following components of compensation — base salary, target annual cash bonus incentive and target long-term equity incentive, as well as target total cash compensation and target total direct compensation. Position-specific market target pay levels are reviewed for utility-specific data from the Willis Towers Watson Energy Services Executive Compensation Survey and general industry data from the Willis Towers Watson General Industry Executive Compensation Survey. For staff jobs, competitive rates were developed for each of the two distinct market reference points, as well as an average of the two market reference points. For utility operations jobs, we only used the utility-specific data due to the industry-specific nature of the roles. The market data were aged and size-adjusted using regression analysis to correspond to our adjusted revenue scope. The adjusted revenue scope accounts for our unique business model and reflects the competitive incremental revenue that would normally be embedded in rates to reflect a typical cost of goods sold factor.

Our compensation strategy is to target compensation to be in the range between the median and 75 ^th percentile of the market data, based on consideration of individual characteristics (performance, experience, etc.), internal equity and other factors. In February 2017, the Committee reviewed the benchmarking study conducted by its independent consultant comparing NEO target total direct compensation, which is the sum of base salary, target annual incentives and target long-term incentives, to the 50 ^th , 65 ^th and 75 ^th percentile survey data to assess the market competitiveness of our compensation opportunities. Overall, the study found target total direct compensation provided to our NEOs is within the targeted range. This is generally achieved by having base salaries at the lower end of the targeted market range with higher target incentive opportunities that combine to provide competitive target total direct compensation.

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

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

The Committee reviewed and considered each element of compensation and the resulting target total direct compensation, along with the objectives of our compensation program, the input of the CEO and the market data to set the 2018 target pay levels. The Committee did not determine the mix of compensation elements using a pre-set formula. In setting executive compensation levels, the Committee retained full discretion to consider or disregard data collected through benchmarking studies. Compensation decisions also considered individual and Company performance, retention concerns, the importance of the position, internal equity and other factors.

Key Components of Our NEO Compensation Program

The key components of our executive compensation program are discussed below.

•	Base Salary — provides sufficient competitive pay to attract and retain experienced and successful executives.

•	Cash Bonus Incentive — encourages and rewards contributions to our annual corporate performance goals.

•	Long Term Equity Incentives — encourages a multi-year focus on performance, rewards building long-term shareholder value and helps retain NEOs.

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The other elements of our executive compensation program are discussed below under the heading “Other Components of Our Executive Compensation Program” which summarize the benefit programs that are available to our NEOs.

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

Base Salary

The Committee annually reviews and approves the base salaries, and any adjustments thereto, of the NEOs. In making these determinations, the Committee considers the executive’s job responsibilities, individual performance, leadership and years of experience, the performance of the Company, the recommendation of the CEO (except for the base salary of the CEO) and the target total direct compensation package as well as the benchmarking analysis conducted by its advisor.

The 2018 base salaries for the NEOs, including any year-over-year change, were:

NEO		2017 Base Salary				2018 Base Salary				Percent Increase
Linda H. Apsey		$	725,000			$	755,000			4.1	%
Gretchen L. Holloway		350,000				370,000				5.7	%
Jon E. Jipping		535,000				555,000				3.7	%
Daniel J. Oginsky		450,000				468,000				4.0	%
Christine Mason Soneral		365,000				378,000				3.6	%

Annual Corporate Performance Bonus

Early each year, the Committee has approved our annual corporate performance bonus plan goals and targets, which are based on key Company objectives relating to operational excellence and superior financial performance. The corporate performance goals and targets were designed to align the interests of customers, shareholders and management, and encourage teamwork and coordination among all of our executives and employees with a common focus on the growth and success of the Company. Target levels for the corporate performance goals were determined based on long-term strategic plans, historical performance, expectations for future growth and desired improvement over time.

The annual bonus plan performance goals were individually weighted. Weights were assigned to each goal based on areas of focus during the year and difficulty in achieving target performance. Weights were also assigned so that there was a balance between operational and financial goals. Each goal operated independently, and, for most goals, there was not a range of acceptable performance; if a goal was not achieved, there was no payout for that goal. The plan would not pay for achieving below-target performance on any goal, but would pay for achievement of target performance on those goals that were achieved even though other goals were not achieved. Where performance goals were stated in a range, the threshold goals were generally expected to be achieved while the maximum goals were considered “stretch” goals with lower expectation of achievement. The bonus goal targets were established to motivate NEOs toward operational excellence and superior financial performance and were designed to be challenging to meet, while remaining achievable.

For 2018 , financial measures plus the capital project plan determined 50% of the target bonus opportunity, while operational performance measures determined the remaining 50% of the target bonus opportunity. This reflected the inherent importance of driving operational performance, reliability and needed investment in our transmission system for the benefit of our customers.

The annual corporate performance bonus plan consisted of three primary measurement categories: Financial, Safety & Compliance, and System Performance. Our safety, operations and security goals were established to deliver high performance in core company operations. Benchmarks and metrics were used in connection with these goals to establish a level of performance in the top decile or quartile within our industry. Likewise, our infrastructure protection goals led to the deployment of industry leading practices resulting in a generally enhanced security posture.

Corporate performance goal criteria approved by the Committee for 2018 , the rationale for the target goal (in some cases in relation to the prior year target) and actual bonus results, were as set forth below.

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Financial goals represented 20% of the total maximum annual bonus target and included specific measures for Non-Field Operation and Maintenance Expense and Net Income.

Category

Goal

Rationale for Goal

Rationale for Target Goal

Potential Payout

2018 Results

Actual Payout

Financial 20% Maximum Potential Payout

Non-field Operation and Maintenance Expense and General and Administrative Expenses

Controlling general and administrative expenses is an important part of controlling rates charged to transmission customers.

Target is consistent with the approach used in 2017 and based on the 2018 Board-approved budget. Non-Field O&M and G&A expense at or under budget of $161 million.

10

%

$148 million

10%

Adjusted Net Income (1)

Represents the Company’s financial performance as it reflects a true measure of earnings contributions from the operating companies.

Target based on the 2018 Board-approved budget. Net Income from our Regulated Operating Subsidiaries at or above $433 million to achieve 10%; Net Income at or above $411 million to achieve 5%.

5% - 10%

$442 million

10%

Total

20

%

20%

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Safety & Compliance goals represented 20% of the total maximum annual bonus target and included specific measures for Lost Time, Recordable Incidents and Infrastructure Protection.

Category		Goal		Rationale for Goal		Rationale for Target		Potential Payout			2018 Results		Actual Payout
Safety & Compliance 20% Maximum Potential Payout		Safety as measured by lost time		Maintaining the safety of our employees and contractors is a core value and is at the foundation of our success.		Target number of incidents remained the same as prior years and was based on industry top decile performance, which reflects an aggressive view and philosophy on the importance of safety. 2 or fewer lost work day cases for injuries to Company employees and specified contract employees.		5	%		0		5%
		Safety as measured by recordable incidents		Maintaining the safety of our employees and contractors is a core value and is at the foundation of our success.		Target number of incidents remained the same as prior year and was based on industry top decile performance, which reflects an aggressive view and philosophy on the importance of safety. 9 or fewer recordable incidents for injuries to Company employees and specified contract employees.		5	%		6		5%
		Infrastructure Protection		Maintaining cyber and physical security is critical to ensuring system reliability and ongoing operations.		Goal focused on implementing updated security objectives. Emphasized securing our information systems and physical space, helping protect our most important assets. Implementation of the 2018 Cyber and Physical Security Plans, as presented to and approved by the Board of Directors, each goal worth 5%.		10	%		Completed		10%
Total								20	%				20%

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System Performance goals represented 60% of the total maximum annual bonus target and included specific measures for System Outages, Maintenance Plans and Capital Project Plan. Achievement of targets for outage frequency were made more difficult in 2018 from previous years.

Category		Goal		Rationale for Goal		Rationale for Target		Potential Payout			2018 Results		Actual Payout
System Performance and Capital Project Plan 60% Maximum Potential Payout		Outage frequency		Reducing and limiting system outages are critical to ensuring system reliability.		Target reduced from prior year. Number of Forced, Sustained Line Outages, excluding the "External" cause classification, for: ITCTransmission (13 or fewer, representing top decile performance); METC (25 or fewer, representing top decile performance); ITC Midwest (68 or fewer, representing top decile performance, no more than 57 at the 69kV level representing top quartile performance.); Each target is worth 5%.		15	%		ITCTransmission - 13 METC - 26 ITC Midwest - 52/ 45		10%
		Field Operation and Maintenance Plan		Performing necessary preventive maintenance is critical to ensuring system reliability.		Target is reflective of goal to complete the normal maintenance schedule of high priority maintenance activities. Complete high priority 2018 Field O&M Initiatives for: ITCTransmission (15) METC (13) ITC Midwest (10) Each subsidiary target worth 5%.		15	%		All high priority initiatives completed		15%
		Capital Project Plan		Performing necessary system upgrades is critical to ensuring system reliability, providing a robust transmission grid and delivering financial performance.		Target is based on accrued capital investment. The maximum payout represents the risk-adjusted capital investment plan for 2018, with a threshold level also established. Complete $665M of the 2018 Capital Expenditure budget to achieve 30%; Complete $630M to achieve 15%.		15 - 30%			$779 million		30%
								60	%				55%
Total Bonus (as a percent of target bonus level)								100	%				95%

____________________________

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

(in millions)	2018
Net Income of Regulated Operating Subsidiaries	$	437
Adjustments Related to ROE Matters	5
Adjusted Net Income	$	442

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

Measure	Threshold	Achievement (1)	Multiplier	Weight	Result
Accrued Capital Investment	$715M	$779M	2.00x	25%	0.50x
Establish 5-Year Business Plan	$3.5B	Goal Met	2.00x	25%	0.50x
Adjusted Consolidated Net Income (2)	$340.5M	$342M	1.50x	25%	0.38x
Development Goals	1 Goal	Not Met	1.00x	25%	0.25x
Bonus Multiplier					1.63x

____________________________

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

(2)	We utilize adjusted consolidated net income as a criterion in measuring achievement of financial goals for the executive bonus multiplier. This non-GAAP financial measure reconciles to consolidated net income of ITC Holdings as follows:

(in millions)	2018
Net Income	$	330
Development Expenses Not Included in Business Plan	7
Adjustments Related to ROE Matters	5
Adjusted Consolidated Net Income	$	342

Each measure has an established scale, which includes a threshold level and below equating to a 1.00x multiplier, having no impact on the bonus award, to a maximum of 2.00x, which would increase the bonus by 100%. Achievement against performance scales related to each of the above metrics produced an executive bonus multiplier of 1.63x. This performance factor was applied to each executive’s ACPB to produce a final payment of approximately 154.8% of target.

Bonuses are based on a target bonus, which for each executive is a percentage of his or her base salary. The Committee considers each individual’s job responsibilities and the results of its benchmarking analysis when determining the base bonus percentage for the executive officers, including the NEOs, which we refer to as the “target bonus levels”. Target bonus levels for 2018 were 100% of base salary for each NEO.

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

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Long-Term Incentives

The Committee provides and maintains a long-term equity incentive program under the 2017 Omnibus Plan. In February 2018, the Committee approved grants of SBUs and PBUs to employees, including the NEOs, based on our CEO’s recommendation (except for grants to the CEO), and also on the Committee’s assessment of the performance of the Company and the executive. Award opportunities for the NEOs were provided in a mix of PBUs (weighted 67%) and SBUs (weighted 33%). The PBUs can be earned for results in two equally-weighted measures, Total Shareholder Return (relative to a peer group) and cumulative consolidated net income, over the three-year performance period. Each unit is generally equivalent to one share of Fortis stock (as traded on the Toronto Stock Exchange) and earned units are payable in cash. Awards to the CEO were also presented to the Board of Directors by the Committee and ratified by the Board of Directors. The amounts and more detailed terms of the 2018 SBU and PBU grants made under the 2017 Omnibus Plan are described in the narrative following the Grants of Plan-Based Awards Table. The awards were designed to reward, motivate and encourage long-term performance, act as a retention mechanism, and further align the interests of the NEOs with the interests of the shareholder. Total value for the award for each grantee was determined based on a percentage of salary. For the NEOs, when the 2018 awards were made, the award values were targeted to be:

NEO	Grant Value Percent of Salary
Ms. Apsey	250	%
Ms. Holloway	175	%
Mr. Jipping	175	%
Ms. Mason Soneral	175	%
Mr. Oginsky	175	%

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

Other Components of Our Executive Compensation Program

Pension Benefits . As is common in our industry and as established pursuant to our initial formation requirements included in the acquisition agreement with DTE Energy for ITCTransmission, we maintain a tax-qualified defined benefit retirement plan for eligible employees, comprised of a traditional pension component and a cash balance component. All employees, including the NEOs, participate in either the traditional component or the cash balance component. We have also established a supplemental nonqualified, noncontributory retirement benefit plan for selected management employees: the Executive Supplemental Retirement Plan, or ESRP, in which all of the NEOs participate. This plan provides for benefits that supplement those provided by our qualified defined benefit retirement plan. Benefits payable to the NEOs pursuant to the retirement plans are set by the terms of those plans. The Committee exercises no regular discretionary authority in the determination of benefits. The retirement plans may be modified, amended or terminated at any time, although no such action may reduce a NEO’s earned benefits. See “Pension Benefits” for information regarding participation by the NEOs in our retirement plans as well as a description of the terms of the plans.

Benefits and Perquisites. The NEOs participate in a variety of benefit programs, which are designed to enable us to attract and retain our workforce in a competitive marketplace. These programs include our Savings and Investment Plan, which consists of an employee deferral contribution component and an employer safe-harbor matching contribution component.

Our NEOs are provided a limited number of perquisites in addition to benefits provided to our other employees. The purpose of these perquisites is to minimize distractions from the NEOs’ attention to important Company initiatives, to facilitate their access to work functions and personnel, and to encourage interactions among NEOs and others within professional, business and local communities. NEOs are provided perquisites such as auto allowance, financial, estate and legal planning, income tax return preparation, annual physical, club memberships, and personal liability insurance. Additionally, we own aircraft to facilitate the business travel schedules of our executives and other employees, particularly to locations that do not provide efficient commercial flight schedules. Ms. Apsey and guests who travel with her are permitted to travel for personal business on our aircraft, with an annual maximum of 50 flight hours for such personal travel. Ms. Apsey incurs imputed income for all guests and herself for personal travel in the amount of the incremental cost to the Company of such travel.

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We purchase tickets to various sporting, civic, cultural, charity and entertainment events. We use these tickets for business development, partnership building, charitable donations and community involvement. If not used for business purposes, we may make these tickets available to employees, including the NEOs, as a form of recognition and reward for their efforts. Because such tickets have already been purchased, we do not believe that there is any aggregate incremental cost to the Company, if a NEO uses a ticket for personal purposes.

None of the NEOs are reimbursed for income taxes associated with the value of the perquisites. The Committee continues to monitor and review the Company’s perquisite program. Perquisites are further discussed in footnote 5 to the “Summary Compensation Table”.

Potential Severance Compensation . Pursuant to their employment agreements, each NEO is entitled to certain benefits and payments upon a termination of his or her employment. Benefits and payments to be provided vary based on the circumstances of the termination. We believe it is important to provide these protections in order to ensure our NEOs will remain engaged and committed to us during an acquisition of the Company or other transition in management. See “Employment Agreements and Potential Payments Upon Termination or Change in Control” for further detail on these employment agreements, including a discussion of the compensation to be provided upon termination or a change in control.

Recoupment Policy

Our Recoupment Policy provides that in the event of any restatement of financial results, our NEOs will be required to reimburse the Company for an amount equal to the sum of:

•

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

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

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

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

A. DOUGLAS ROTHWELL        THOMAS G. STEPHENS

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Summary Compensation

The following table provides a summary of compensation paid or accrued by the Company and its subsidiaries to or on behalf of the NEOs for services rendered by them during each of the last three calendar years, as required by SEC rules and regulations. The material terms of plans and agreements pursuant to which certain items set forth below were paid are discussed elsewhere in Compensation of Executive Officers and Directors.

Summary Compensation Table

Name		Year		Salary ($)				Bonus ($) (1)				Stock Awards ($) (2)				Non-Equity Incentive Plan Compensation ($) (3)				Change in Pension Value & Non-qualified Deferred Compensation Earnings ($)(4)				All Other Compensation ($) (5)				Total ($)
(a)		(b)		(c)				(d)				(e)				(f)				(g)				(h)				(i)
Linda H. Apsey, President & CEO		2018		$	752,712			$	—			$	1,747,386			$	1,169,118			$	123,927			$	66,909			$	3,860,052
		2017		725,000				644,700				1,760,834				1,205,313				232,747				57,751				4,626,345
		2016		635,146				659,662				1,074,490				1,244,401				291,249				41,301				3,946,249
Gretchen L. Holloway SVP & CFO		2018		367,962				—				599,433				572,945				81,152				34,351				1,655,843
		2017		317,981				265,000				552,539				581,875				80,454				33,126				1,830,975
		2016		210,116				60,000				139,761				168,337				71,163				31,312				680,689
Jon E. Jipping, EVP & COO		2018		553,674				—				899,149				859,418				63,980				37,869				2,414,090
		2017		529,289				538,100				909,553				889,438				345,722				37,694				3,249,796
		2016		503,931				539,333				878,517				982,615				365,553				37,269				3,307,218
Daniel J. Oginsky, EVP & CAO		2018		466,685				—				758,200				724,698				51,865				36,556				2,038,004
		2017		445,327				444,150				765,053				748,125				177,356				35,972				2,615,983
		2016		424,627				454,458				740,250				827,980				213,915				35,497				2,696,727
Christine Mason Soneral, SVP & General Counsel		2018		377,204				—				612,373				585,333				66,424				35,250				1,676,584
		2017		362,404				529,899				620,551				606,813				146,625				36,378				2,302,670
		2016		351,346				524,557				612,487				695,590				135,364				35,675				2,355,019

____________________________

(1)

The compensation amounts reported in this column include, bonuses paid in connection with project milestones and retention bonuses. Bonuses paid in connection with our annual corporate performance plan are reported in the “Non-Equity Incentive Plan Compensation” column of the Summary Compensation Table. In 2016, the NEOs, received certain project-related bonuses in recognition of the successful completion of various transmission development milestones. In 2016, Ms. Mason Soneral received $300,000 since the Merger was closed before December 31, 2016. In 2016, all of the NEOs received 30% of their retention award due to the closing of the Merger and, in October 2017, they received the remaining 70% of their retention award. In 2017, Ms. Mason Soneral earned $162,399 in accordance with the retention payments related to her employment agreement amendment. In 2017, Ms. Holloway received a lump sum payment of $125,000 and Mr. Jipping received a lump sum payment of $11,000 due to their expanding responsibilities. These bonuses are set forth in the following table.

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Name		Year		Retention Bonus ($)				Merger Completion ($)				Other Bonuses ($)				Total Bonus ($)
Linda H. Apsey		2018		$	—			$	—			$	—			$	—
		2017		644,700				—				—				644,700
		2016		276,300				—				383,362				659,662
Gretchen L. Holloway		2018		—				—				—				—
		2017		140,000				—				125,000				265,000
		2016		60,000				—				—				60,000
Jon E. Jipping		2018		—				—				—				—
		2017		527,100				—				11,000				538,100
		2016		225,900				—				313,433				539,333
Daniel J. Oginsky		2018		—				—				—				—
		2017		444,150				—				—				444,150
		2016		190,350				—				264,108				454,458
Christine Mason Soneral		2018		—				—				—				—
		2017		529,899				—				—				529,899
		2016		157,500				300,000				67,057				524,557

(2)	The amounts reported in this column represent the fair value of performance shares, restricted shares, PBU awards and SBU awards granted to the NEOs under the 2017 Omnibus Plan, and the 2006 LTIP in accordance with FASB Accounting Standards Codification Topic 718, or ASC 718.

The grant date fair value of the SBU awards is based on the applicable share price on the grant date. The grant date fair value of the PBU awards is based on the applicable share price on the grant date and the expected payout of the performance and market conditions, with the market condition fair value determined using a Monte Carlo simulation valuation model. The SBU awards and PBU awards are liability awards, subject to remeasurement through the vesting date, and settled in cash, see “Grants of Plan-Based Awards.” The 2016 awards only included restricted shares; PBUs and SBUs were awarded in 2017 and 2018.

(3)	The amounts reported in this column include cash awards tied to the achievement of annual Company performance goals under our annual corporate performance bonus plan in effect for each of 2018, 2017 and 2016. For information regarding the corporate goals for 2018, see “Compensation Discussion and Analysis - Key Components of Our NEO Compensation Program - Annual Corporate Performance Bonus."

(4)

All amounts reported in this column pertain to the tax-qualified defined benefit pension plan and the supplemental nonqualified, noncontributory retirement plan maintained by the Company. None of the income on nonqualified deferred compensation was above-market or preferential. Variations in the amounts from year to year reflect an additional year of service and pay changes used in the accrued benefit, as well as changes in assumptions on which the benefits are calculated, for which the formula has not been materially revised. The discount rate used for the present value of accumulated benefits was 4.15% in 2016, 3.67% in 2017 and 4.39% in 2018.

(5)

All Other Compensation includes amounts for auto allowance, financial, estate and legal planning, income tax return preparation, annual physical, club memberships, event tickets, personal liability insurance, personal use of company aircraft and for other benefits such as Company contributions on behalf of the NEOs pursuant to the matching component of the Savings and Investment Plan. Perquisites have been valued for purposes of these tables on the basis of the aggregate incremental cost to the Company. The incremental cost of the personal use of the Company aircraft was determined based upon the Company’s expenses incurred in connection with the actual costs of maintenance, landing, parking, crew and catering and estimated fuel costs relating to Ms. Apsey’s hours of use of the aircraft. Fuel expense was determined by calculating the average fuel cost for the month and the average amount of fuel used per hour. These benefits and perquisites for 2018, 2017 and 2016 are itemized in the table below as required by applicable SEC rules.

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Name		Year		401(k) Match				Personal Use of Company Aircraft				Other Benefits				Total
Linda H. Apsey		2018		$	14,750			$	25,074			$	27,085			$	66,909
		2017		14,400				12,752				30,599				57,751
		2016		14,300				—				27,001				41,301
Gretchen L. Holloway		2018		14,750				—				19,601				34,351
		2017		14,400				—				18,726				33,126
		2016		14,300				—				17,012				31,312
Jon E. Jipping		2018		16,500				—				21,369				37,869
		2017		16,200				—				21,494				37,694
		2016		15,900				—				21,369				37,269
Daniel J. Oginsky		2018		14,750				—				21,806				36,556
		2017		14,400				—				21,572				35,972
		2016		14,300				—				21,197				35,497
Christine Mason Soneral		2018		14,750				—				20,500				35,250
		2017		14,400				—				21,978				36,378
		2016		14,300				—				21,375				35,675

We purchase tickets to various sporting, civic, cultural, charity and entertainment events. We use these tickets for business development, partnership building, charitable donations and community involvement. If not used for business purposes, we may make these tickets available to employees, including the NEOs, as a form of recognition and reward for their efforts. Because such tickets have already been purchased, we do not believe that there is any aggregate incremental cost to the Company, if a NEO uses a ticket for personal purposes.

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Grants of Plan-Based Awards

The following table sets forth information concerning each grant of an award made to a NEO during 2018.

Name		Grant Date		Award Type		Estimated Future Payouts Under Non-Equity Incentive Plan Awards												Estimated Future Payouts Under Equity Incentive Plan Awards									All Other Stock Awards: Number of Shares of Stock or Units (#)			Grant Date Fair Value of Stock and Option Awards ($)(3)
						Threshold ($)				Target ($)(1)				Maximum ($)(1)				Threshold (#)			Target (#)(2)			Maximum (#)(2)
(a)		(b)				(c)				(d)				(e)				(f)			(g)			(h)			(i)			(j)
Linda H. Apsey		3/7/2018		SBU		$	—			$	—			$	—			—			—			—			17,195			$	580,159
		3/7/2018		PBU		—				—				—				17,195			34,390			78,362			—			1,167,245
				ACPB		—				755,000				1,510,000				—			—			—			—			—
Gretchen L. Holloway		3/7/2018		SBU		—				—				—				—			—			—			5,899			199,032
		3/7/2018		PBU		—				—				—				5,899			11,797			23,594			—			400,407
				ACPB		—				370,000				740,000				—			—			—			—			—
Jon E. Jipping		3/7/2018		SBU		—				—				—				—			—			—			8,848			298,532
		3/7/2018		PBU		—				—				—				8,848			17,696			35,392			—			600,627
				ACPB		—				555,000				1,110,000				—			—			—			—			—
Daniel J. Oginsky		3/7/2018		SBU		—				—				—				—			—			—			7,461			251,734
		3/7/2018		PBU		—				—				—				7,461			14,922			29,844			—			506,474
				ACPB		—				468,000				936,000				—			—			—			—			—
Christine Mason Soneral		3/7/2018		SBU		—				—				—				—			—			—			6,026			203,317
		3/7/2018		PBU		—				—				—				6,026			12,052			24,104			—			409,062
				ACPB		—				378,000				756,000				—			—			—			—			—

____________________________

(1)

The amount shown in Column (d) represents the potential payout for the ACPB based on “target bonus levels.” The amount payable assuming maximum achievement of all bonus goals is set forth in column (e). Actual dollar amounts paid are disclosed and reported in the “Summary Compensation Table” as Non-Equity Incentive Plan Compensation. For more information regarding the ACPBs, see “Compensation Discussion and Analysis — Key Components of Our NEO Compensation Program — Annual Corporate Performance Bonus.”

(2)

Payment of each PBU award is contingent on meeting performance targets based on (1) Fortis Total Shareholder Return in comparison to the Total Shareholder Return during the performance period for each of the companies that comprise the 2018 Fortis peer group and (2) cumulative consolidated net income for each fiscal year during the performance period. The performance measures are independent of each other. If threshold, target or maximum performance goals are attained in the performance period, 50%, 100% or 200% of the target amount, respectively, may be earned. If actual performance falls between threshold, target and maximum, the awards would be prorated between levels based on performance outcome. For more information regarding performance share awards, see “Grant of Plan-Based Awards - Performance-Based Unit Award Agreements.”

(3)

Grant Date Fair Value consists of SBUs and PBUs awarded under the 2017 Omnibus Plan with a grant date of March 7, 2018. The PBUs reflected here are recorded at fair value at the date of grant, which was $33.94 per share. The SBUs reflected here are recorded at fair value at the date of grant, which was $33.74 per share. Share fair values were converted from Canadian Dollars to US Dollars using the “Award Conversion Rate” defined in the 2017 Omnibus Plan.

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

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The Committee had the power to award SBUs and PBUs in the form of equity or cash under the 2017 Omnibus Plan with the terms of each award set forth in a written agreement with the recipient. Grants made in 2018 to the NEOs were made under the 2017 Omnibus Plan pursuant to terms stated in the SBU and PBU award agreements.

Performance-Based Unit Award Agreements

The PBU award agreements entered into with each NEO in 2018 (each a “PBU Agreement”) provide generally that the award will vest on December 31, 2020 (the “Vesting Date”) to the extent one or more of the performance goals are met and if the grantee continues to be employed by the Company through the Vesting Date. One-half of the Target Number of PBUs shall be related to the Fortis Total Shareholder Return goal (the “TSR goal”) and one-half of the Target Number of PBUs shall be related to the Cumulative Consolidated Net Income goal (the “CCNI goal”). The PBUs will become earned as set forth in the following table:

Measurement Category	Goal at Threshold	Shares at Threshold	Goal at Target	Shares at Target	Goal at Maximum	Shares at Maximum
Fortis Total Shareholder Return	30 th  percentile	50% of TSR Target Units	50 th  percentile	100% of TSR Target Units	85th percentile	200% of TSR Target Units
Cumulative Consolidated Net Income	99% of Target	50% of CCNI Target Units	100% of Target	100% of CCNI Target Units	102% of Target	200% of CCNI Target Units

The performance period for the award is January 1, 2018 through December 31, 2020 (the “Payment Criteria Period”). The performance measures are independent of each other; that is, if the threshold level of one performance measure is attained, units relating to that measure will be “earned” (subject to vesting as otherwise provided in the PBU Agreement) even if the threshold level of the other performance measure is not attained. The number of PBUs that are “earned” with respect to each performance measure will be prorated between levels based on performance. The Committee will have discretion to reduce the number of PBUs earned under certain circumstances.

Total Shareholder Return of Fortis will be compared to each of the companies (the “Peer Companies”) listed in the Fortis Peer Group 2018 Report excluding any company that is no longer traded on the Toronto Stock Exchange or a “national securities exchange” at the end of the Payment Criteria Period. The Peer Companies currently consist of the following 25 U.S. and Canadian public utility companies:

Alliant Energy Corporation	Emera Incorporated	PG&E Corporation
Ameren Corporation	Entergy Corporation	Pinnacle West Capital Corporation
Atmos Energy Corporation	Eversource Energy	PPL Corporation
Canadian Utilities Limited	FirstEnergy Corp.	Public Service Enterprise Group Inc.
CenterPoint Energy Inc.	Great Plains Energy Incorporated	Sempra Energy
CMS Energy Corporation	Hydro One Limited	UGI Corp.
Consolidated Edison Inc.	NiSource Inc.	WEC Energy Group, Inc.
DTE Energy Company	OGE Energy Corp.	Xcel Energy Inc.
Edison International

The Total Shareholder Return of Fortis and the Peer Companies shall be computed in U.S. dollars as follows:

A: Calculate the Market Price as of the first day of the Payment Criteria Period (if necessary, converted into U.S. dollars based on the Award Conversion Rate as defined in the 2017 Omnibus Plan)

B: Calculate the Market Price as of the last day of the Payment Criteria Period (if necessary, converted into U.S. dollars based on the Award Conversion Rate)

C: Calculate the total dividends paid per share of its common stock (or equivalent security) during the Payment Criteria Period (if necessary, converted into U.S. dollars based on the Award Conversion Rate)

Total Shareholder Return = ((B - A) + C)/A

Consolidated Net Income for the Company for each calendar year in the Payment Criteria Period shall be equal to net income as set forth in the Company’s audited consolidated financial statements contained in its annual report on Form 10-K for such year, as adjusted for extraordinary items and changes in Return on Equity, in each case in the Committee’s discretion. Cumulative Consolidated Net Income for the Company during the Payment Criteria Period shall be the sum of the Consolidated Net Income for each of the three years in the Payment Criteria Period.

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If the grantee ceases to be employed before the Vesting Date due to death or disability, the grantee will receive, following the Vesting Date, the number of PBUs to which the grantee would have otherwise been entitled if the grantee had remained employed through the Vesting Date. If the grantee ceases to be employed before the Vesting Date due to “Retirement” or “Involuntary Termination Without Cause,” and the grantee has been in service of the Company for one year or more after the grant date, the grantee will receive, following the Vesting Date, a pro rata portion (based on the period served from the grant date to termination) of the number of PBUs to which the grantee would have otherwise been entitled. If termination occurs prior to the Vesting Date other than as a result of death, disability, Retirement or Involuntary Termination Without Cause, grantee will forfeit the award. “Involuntary Termination Without Cause” means a termination of the grantee’s employment by the Company other than due to the grantee’s death, disability, Retirement, voluntary resignation or for “Cause” (as defined in the PBU Agreement). “Retirement” is defined to mean termination of grantee’s employment with the Company upon or after attaining “normal retirement age” (as defined in the International Transmission Company Retirement Plan).

Upon a “Change of Control”, as defined in the 2017 Omnibus Plan, all outstanding PBUs become redeemable on the trading day that is immediately prior to the effective date of the consummation of the event resulting in the Change of Control (the “Change of Control Redemption Date”). In the event of a Change of Control, the payout percentage for outstanding PBUs is the product of (i) the higher of (A) 100% of the target number of PBUs in the award or (B) the actual payout percentage based on the Committee’s assessment of performance of the payment criteria from the beginning of the Payment Criteria Period for the award through the date of the Change of Control, multiplied by (ii) a fraction, the numerator of which is the number of days elapsed in the Payment Criteria Period for the award through the date on which the Change of Control occurred and the denominator of which is the total number of days in the payment criteria period for the award.

Grantees are entitled to receive additional PBUs equal to the “dividend equivalent” when a cash dividend is paid on common shares of Fortis stock (each a “Common Share”). Such “dividend equivalent” shall be equal to a fraction where the numerator is the product of (a) the number of PBUs in the grantee’s account on the date that the dividends are paid, including PBUs previously credited as “dividend equivalents,” multiplied by (b) the dividend paid per Common Share and the denominator of which is the “Market Price” of one Common Share calculated on the date that dividends are paid, converted to U.S. dollars based on the Award Conversion Rate. All “dividend equivalent” PBUs shall have a Vesting Date which is the same as the Vesting Date for the PBUs in respect of which such additional PBUs are credited.

Service-Based Unit Award Agreements

The SBU award agreements entered into with each NEO in 2018 (each a “SBU Agreement”) provide generally that, so long as the grantee remains employed by the Company, the SBUs fully vest upon the earlier of (i) December 31, 2020 (the “Vesting Date”) or (ii) the grantee's death or disability. If the grantee ceases to be employed before the Vesting Date due to “Retirement” or “Involuntary Termination Without Cause” and the grantee has been in service of the Company for one year or more after the grant date, the grantee will receive a pro rata portion (based on the period served from the grant date to termination) of the number of SBUs to which the grantee would have otherwise been entitled. If termination occurs prior to the Vesting Date other than as a result of death, disability, Retirement or Involuntary Termination Without Cause, grantee will forfeit the award. Upon a Change of Control, all unvested SBUs are deemed to be fully vested and redeemable on the Change of Control Redemption Date. “Retirement”, “Involuntary Termination Without Cause” and “Change of Control” are defined in the same manner as defined in the description of the PBU Agreement disclosed above. Grantees are entitled to receive additional dividend equivalent SBUs in the same manner as defined in the description of the PBU Agreement disclosed above.

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Outstanding Equity Awards at Fiscal Year-End

The following table provides information with respect to SBUs and PBUs that have not vested as of the end of 2018 held by the NEOs.

Name	Number of Shares or Units of Stock That Have Not Vested (#) (SBUs)	Market Value of Shares or Units of Stock That Have Not Vested ($) (SBUs) (1)			Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#) (PBUs)	Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($) (PBUs) (1)
(a)	(b)	(c)			(d)	(e)
Linda H. Apsey	20,937 (2)	$	698,462		41,875 (4)	$	1,396,960
	17,716 (3)	591,003			35,432 (5)	1,182,005
Gretchen L. Holloway	6,570 (2)	219,165			13,140 (4)	438,366
	6,078 (3)	202,752			12,154 (5)	405,470
Jon E. Jipping	10,815 (2)	360,783			21,631 (4)	721,601
	9,116 (3)	304,111			18,232 (5)	608,223
Daniel J. Oginsky	9,097 (2)	303,487			18,194 (4)	606,938
	7,687 (3)	256,439			15,374 (5)	512,878
Christine Mason Soneral	7,376 (2)	246,155			14,758 (4)	492,311
	6,209 (3)	207,117			12,417 (5)	414,235

(1) Value was determined by multiplying the number of units that have not vested by the closing price of Fortis common stock as of December 31, 2018 ($33.36).

(2) These unvested SBUs were granted in 2017 and generally vest on December 31, 2019.

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

(4) These unvested PBUs were granted in 2017 and generally vest on December 31, 2019. The award contains performance conditions established by the Committee. In order for PBUs to vest such performance conditions must be achieved. Amounts reported reflect PBU payouts as if the target performance goals have been achieved.

(5) These unvested PBUs were granted in 2018 and generally vest on December 31, 2020. The award contains performance conditions established by the Committee. In order for PBUs to vest such performance conditions must be achieved. Amounts reported reflect PBU payouts as if the target performance goals have been achieved.

Equity grants made to NEOs in 2017 and 2018 were made pursuant to the 2017 Omnibus Plan. The terms of the grants are described above in the narrative discussion accompanying the “Grants of Plan-Based Awards” Table.

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Pension Benefits

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

Pension Benefits Table

Name		Plan Name		Number of Years Credited Service (#)(1)			Present Value of Accumulated Benefit ($)(2)				Payments During Last Fiscal Year ($)
(a)		(b)		(c)			(d)				(e)
Linda H. Apsey		Cash Balance Component		24.58			$	378,380			N/A
		ESRP Shift		N/A			35,044				N/A
		Total Qualified Plan					413,424				N/A
		ESRP		15.83			1,543,345				N/A
Gretchen Holloway		Cash Balance Component		14.95			238,432				N/A
		Total Qualified Plan					238,432				N/A
		ESRP		3.91			179,050				N/A
Jon E. Jipping		Traditional Component		28.03			1,361,010				N/A
		Total Qualified Plan					1,361,010				N/A
		ESRP		13.92			1,317,135				N/A
Daniel J. Oginsky		Cash Balance Component		14.20			299,333				N/A
		Total Qualified Plan					299,333				N/A
		ESRP		14.20			1,007,998				N/A
Christine Mason Soneral		Cash Balance Component		11.29			237,397				N/A
		Total Qualified Plan					237,397				N/A
		ESRP		11.29			536,269				N/A

____________________________

(1)	Credited service is estimated as of December 31, 2018 and represents the service reflected in the determination of benefits. For determining vesting, service with DTE Energy is counted for the Qualified Plan only.

For Ms. Apsey and Mr. Jipping, the credited service for the cash balance and traditional components of the Qualified Plan, respectively, includes service with DTE Energy. The Company began operations on February 28, 2003, following its acquisition of ITCTransmission from DTE Energy. As of that date, the benefits from DTE Energy’s qualified plan that had accrued, as well as the associated assets from DTE Energy’s pension trust, were transferred to the Qualified Plan. Therefore, even though DTE Energy service is included in determining the benefits under the traditional and cash balance components of the Qualified Plan, the benefits associated with this additional service do not represent a benefit augmentation, but rather a transfer of benefit liability and associated assets from DTE Energy’s qualified plan to the Qualified Plan. With respect to the ESRP, credited service includes Company service only for the period during which the NEO was an ESRP participant.

(2)

The “Present Value of Accumulated Benefit” is the estimated lump-sum equivalent value measured as of December 31, 2018 (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, 2018. The rate at which future expected benefit payments were discounted in calculating present values was 4.39%, the same rate used for fiscal year-end 2018 financial accounting disclosure of the Qualified Plan. The future annual earnings rate on account balances under the cash balance and ESRP shift components of the Qualified Plan, and for ESRP benefits, was assumed to be 3.15% for 2019 and 4.5% thereafter.

We assumed no NEOs would die or become disabled prior to retirement, or terminate employment with us prior to becoming eligible for benefits unreduced for early retirement. The assumed retirement age for each

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executive was generally the earliest age at which benefits unreduced for early retirement were available under the respective plans. For the traditional component of the defined benefit plan, that age is the earlier of (1) age 58 with 30 years of service (including service with DTE Energy), or (2) age 60 with 15 years of service. For consistency, we generally use the same assumed retirement commencement age for other benefits, including benefits expressed as an account value where the concept of benefit reductions for early retirement is not meaningful. The assumed retirement benefit commencement ages were 58 for each NEO.

Post-retirement mortality was assumed to be in accordance with the Adjusted RP-2014 table projected for future mortality improvements with MP-2017 generational scale. Benefits under the traditional component of the Qualified Plan were assumed to be paid as a monthly annuity payable for the lifetime of the employee. For all other benefits, payment was assumed to be as a single lump sum, although other actuarially equivalent forms are available.

We maintain one tax-qualified noncontributory defined benefit pension plan and one supplemental nonqualified, noncontributory defined benefit retirement plan. First, we maintain the Qualified Plan, which provides funded, tax-qualified benefits up to the limits on compensation and benefits under the Internal Revenue Code. Generally, all of our salaried employees, including the NEOs, are eligible to participate.

We maintain the ESRP, in which all of our NEOs participate. The ESRP provides additional retirement benefits which are not tax qualified.

The following describes the Qualified Plan and the ESRP, and pension benefits provided to the NEOs under those plans.

Qualified Plan

There are two primary retirement benefit components of the Qualified Plan. Each NEO earns benefits from the Company under only one of these primary components.

Because our first operating utility subsidiary was acquired from DTE Energy, a component of the Qualified Plan bears relation to the DTE Energy Corporation Retirement Plan (the “DTE Plan”). Generally, persons who were participants in the “traditional component” of the DTE Plan as of February 28, 2003 (the date ITCTransmission was acquired from DTE Energy) earn benefits under the traditional component of our Qualified Plan. All other participants earn benefits under the cash balance component. Ms. Apsey also has benefits under the ESRP shift described below.

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

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

Traditional Component of Qualified Plan

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

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

Benefits provided under the Qualified Plan are based on compensation up to a compensation limit under the Internal Revenue Code (which was $275,000 in 2018, 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 $220,000 payable as a single life annuity beginning at normal retirement age in 2018).

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NEOs may retire with a reduced benefit as early as age 45 after 15 years of credited service. If a NEO has 30 years of credited service at retirement, the benefit that would be payable at normal retirement age is reduced for commencement ages below 58. The percentage of the normal retirement benefit payable at sample commencement ages is as follows:

Age 58 and older:    100%

Age 55:             85%

Age 50:             40%

If a NEO has less than 30 years but more than 15 years of credited service at retirement, the benefit that would be payable at normal retirement age is reduced for commencement ages below age 60. The percentage of the normal retirement benefit payable at sample commencement ages is as follows:

Age 60 and older:    100%

Age 55:             71%

Age 50:             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:            58%

Age 55:             36%

Age 50:             23%

Mr. Jipping’s annual accrued benefit payable monthly as an annuity for his lifetime, beginning at age 60, is approximately $111,700. He is fully vested.

Cash Balance Component of Qualified Plan

Mses. Apsey, Holloway and Mason Soneral and Mr. Oginsky participate in the cash balance component of the Qualified Plan. The benefits are stated as a notional account value.

Each year, a NEO’s account is increased by a “contribution credit” equal to 7% of pay. For this purpose, pay is equal to base salary plus bonuses and overtime up to the same compensation limit as applies under the traditional component of the Qualified Plan ($275,000 in 2018). Each year, a NEO’s account is also increased by an “interest credit” based on 30-year Treasury rates.

Upon termination of employment, a vested NEO may elect full payment of his or her account. Alternate forms of benefit (e.g., various forms of annuities) are available as well that have the same actuarial value as the account.

Mses. Apsey, Holloway and Mason Soneral and Mr. Oginsky are entitled to immediate payment of their account value on termination of employment, even if before normal retirement age. Ms. Apsey’s estimated account value as of year-end 2018 is approximately $380,000, Ms. Holloway’s is approximately $238,000, Ms. Mason Soneral’s is approximately $237,000, and Mr. Oginsky’s is approximately $299,000.

ESRP Shift Benefit in Qualified Plan

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

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

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Ms. Apsey has received ESRP shift additions to her Qualified Plan cash balance account. There was no shift of compensation credits for 2018, although previous shifts have continued to earn interest credits. As of year-end 2018, her ESRP shift balance was approximately $354,000.

Executive Supplemental Retirement Plan

The ESRP is a nonqualified retirement plan. Only selected executives participate, including all our NEOs. The purpose of the ESRP is to promote the success of the Company and its subsidiaries by providing the ability to attract and retain talented executives by providing such designated executives with additional retirement benefits.

The ESRP resembles the cash balance component of the Qualified Plan in that benefits are expressed as a notional account value and the vested account balance is payable as a lump sum on termination of employment, although an installment option of equivalent value is also available.

Each year, a NEO’s account is increased by a “compensation credit” equal to 9% of pay. For this purpose, pay is equal to base salary plus any bonus under the Company’s annual corporate performance bonus plan. There is no limit on compensation that may be taken into account as in the Qualified Plan. Each year, a NEO’s account is also increased by an “investment credit” equal to the same earnings rate as the interest credit in the cash balance component of the Qualified Plan, based on 30-year Treasury rates.

The plan has been in effect since March 1, 2003. Vesting occurs at 20% for each year of participation. All of our NEOs are fully vested.

As noted above in the description of the Qualified Plan, a portion of the ESRP account balance may be shifted to the cash balance component of the Qualified Plan each year, as permitted under the rules for qualified plans. Such a shift allows the NEOs to become immediately vested in the account values shifted, and confers certain tax advantages to the NEOs and us. As of December 31, 2018, the ESRP account values, net of the amounts shifted to the Qualified Plan, are as follows:

Ms. Apsey		$	1,548,794
Ms. Holloway		178,770
Mr. Jipping		1,327,132
Mr. Oginsky		1,007,924
Ms. Mason Soneral		536,464

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

Nonqualified Deferred Compensation

We maintain the Executive Deferred Compensation Plan under which nonqualified deferred compensation is permissible. Only selected officers of the Company, including the NEOs, are eligible to participate in this plan. NEOs are allowed to defer up to 100% of their salary and bonus. Investment earnings are based on the various investment options available under the plan, and are selected by the individual NEOs. Distributions will generally be made at the NEO’s termination of employment for any reason. Mr. Jipping elected to participate in 2018, but his deferral will be made in 2019 due to his 2018 bonus payment occurring in 2019. No other NEO currently participates in this plan.

Employment Agreements and Potential Payments Upon Termination or Change in Control

Employment Agreements

As referenced above, we entered into employment agreements with Ms. Apsey and Messrs. Jipping and Oginsky in December 2012 which superseded the employment agreements then in effect. In February 2015, we entered into an employment agreement with Ms. Mason Soneral which superseded her employment agreement then in effect. In July 2017, we entered into an employment agreement with Ms. Holloway, which superseded her employment agreement then in effect. Each employment agreement is subject to automatic one-year employment term renewals each year beginning on its second anniversary, unless either party provides the other with 30 days’ advance written notice of intent not to renew the employment term. Ms. Apsey’s agreement was modified in October 2016 in connection with her appointment as President and Chief Executive Officer and the initial term of the agreement expired on December 31, 2018 but is subject to the automatic one-year renewal provision described above. The following describes the material terms of the employment agreements, as amended, with the NEOs who remained employed by the Company on December 31, 2018.

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The employment agreements provide that each NEO will receive an annual base salary equal to their current base salary, which is subject to annual review and increase by our Board of Directors at its discretion. The employment agreements also provide that NEOs are eligible to receive an annual cash bonus, subject to our achievement of certain performance targets established by our Board of Directors, as detailed in “Compensation Discussion and Analysis.” The employment agreements also provide the NEOs with the right to participate in equity plans, employee benefit plans and retirement plans, including but not limited to welfare plans, retiree welfare benefit plans and defined benefit and defined contribution plans.

In addition, the NEOs’ employment agreements provide for payments by us of certain benefits upon termination of employment. The rights available at termination depend on the situation and circumstances surrounding the terminating event. The terms “Cause” and “Good Reason” are used in the employment agreements of each NEO and an understanding of these terms is necessary to determine the appropriate rights for which a NEO is eligible. The terms are defined as follows:

•

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

•	Good reason means: a greater than 10% reduction in the total value of the NEO’s base salary, target bonus, and employee benefits; or if the NEO’s responsibilities and authority are substantially diminished.

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

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

•	any accrued but unpaid compensation and benefits including:

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

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

◦	Mr. Oginsky, Ms. Mason Soneral and Ms. Holloway: cash balance under the Qualified Plan and vested portion of ESRP balance

•	continued payment of the NEO’s then-current base salary for two years;

•

if the termination is within six months before or two years after a “Change of Control” (as defined in the employment agreements), payment of an amount equal to two times the average of the ACPBs, that were payable to the NEO for the three fiscal years immediately preceding the fiscal year in which his or her employment terminates, payable in equal installments over the period in which continued base salary payments are made;

•	a pro rata portion of the ACPB for the year of termination, based upon the Company’s actual achievement of the performance targets for such year as determined under the annual corporate performance bonus plan and paid at the time that such bonus would normally be paid;

•

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

•	outplacement services for up to two years; and

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•

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

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

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

Payments in the Event of Termination

The benefits to be provided to the NEOs as a result of termination under various scenarios are detailed in the tables below. The tables assume that the termination occurred on December 31, 2018.

Linda H. Apsey - Termination Scenarios: Value of Potential Payments
Total Value of Severance, Benefits and Unvested Equity Awards(1)(2)
		Voluntary Resignation				Involuntary For Cause				Involuntary Not-for-Cause or Voluntary Good Reason				Change In Control (pre-tax)(3)				Disability				Death (pre-retirement)(4)
Compensation
Cash Severance		$	—			$	—			$	1,510,000			$	3,542,243			$	—			$	—
Target Short-term Bonus		—				—				—				—				755,000				755,000
Pro Rata Short-term (Annual) Incentive Comp		—				—				1,255,565				1,255,565				—				—
Retention Awards										—				—				—				—
Service-Based Unit Awards (7)		—				—				223,706				1,262,109				1,262,109				1,262,109
Performance-Based Unit Awards		—				—				447,423				1,287,360				2,524,275				2,524,275
Benefits and Perquisites										—
Retirement Plan		—				—				—				—				—				1,460
ESRP		—				—				—				—				—				5,449
Perquisites		—				—				25,000				25,000				—				—
Health & Welfare Benefits		—				—				29,726				29,726				—				—
Postretirement Welfare Plan (5)		—				—				544,551				544,551				—				—
Total Payout:		$	—			$	—			$	4,035,971			$	7,946,554			$	4,541,384			$	4,548,293

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Gretchen L. Holloway - Termination Scenarios: Value of Potential Payments
Total Value of Severance, Benefits and Unvested Equity Awards(1)(2)
		Voluntary Resignation				Involuntary For Cause				Involuntary Not-for-Cause or Voluntary Good Reason				Change In Control (pre-tax)(3)				Disability				Death (pre-retirement)(4)
Compensation
Cash Severance		$	—			$	—			$	740,000			$	1,292,141			$	—			$	—
Target Short-term Bonus		—				—				—				—				370,000				370,000
Pro Rata Short-term (Annual) Incentive Comp		—				—				615,310				615,310				—				—
Service-Based Unit Awards (7)		—				—				70,195				413,330				413,330				413,330
Performance-Based Unit Awards (8)		—				—				140,402				415,461				826,675				826,675
280G Cutback		—				—				—				(858,180		)		—				—
Benefits and Perquisites
Retirement Plan		—				—				—				—				—				—
ESRP		—				—				—				—				—				—
Perquisites		—				—				25,000				25,000				—				—
Health & Welfare Benefits		—				—				27,714				27,714				—				—
Total Payout:		$	—			$	—			$	1,618,621			$	1,930,776			$	1,610,005			$	1,610,005

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		$	—			$	—			$	1,110,000			$	2,684,336			$	—			$	—
Target Short-term Bonus		—				—				—				—				555,000				555,000
Pro Rata Short-term (Annual) Incentive Comp		—				—				922,965				922,965				—				—
Service-Based Unit Awards (7)		—				—				115,553				650,754				650,754				650,754
Performance-Based Unit Awards (8)		—				—				231,117				664,208				1,301,574				1,301,574
Benefits and Perquisites
Retirement Plan (6)		—				—				—				—				—				—
ESRP		—				—				—				—				—				9,997
Perquisites		—				—				25,000				25,000				—				—
Health & Welfare Benefits		—				—				27,582				27,582				—				—
Total Payout:		$	—			$	—			$	2,432,217			$	4,974,845			$	2,507,328			$	2,517,325

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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-retirement)(4)
Compensation
Cash Severance		$	—			$	—			$	936,000			$	2,261,687			$	—			$	—
Target Short-term Bonus		—				—				—				—				468,000				468,000
Pro Rata Short-term (Annual) Incentive Comp		—				—				778,284				778,284				—				—
Service-Based Unit Awards (7)		—				—				97,202				548,038				548,038				548,038
Performance-Based Unit Awards (8)		—				—				194,392				559,098				1,096,055				1,096,055
Benefits and Perquisites
Retirement Plan		—				—				—				—				—				—
ESRP		—				—				—				—				—				—
Perquisites		—				—				25,000				25,000				—				—
Health & Welfare Benefits		—				—				28,719				28,719				—				—
Total Payout:		$	—			$	—			$	2,059,597			$	4,200,826			$	2,112,093			$	2,112,093

Christine Mason Soneral - Termination Scenarios: Value of Potential Payments
Total Value of Severance, Benefits and Unvested Equity Awards(1)(2)
		Voluntary Resignation				Involuntary For Cause				Involuntary Not-for-Cause or Voluntary Good Reason				Change In Control (pre-tax)(3)				Disability				Death (pre-retirement)(4)
Compensation
Cash Severance		$	—			$	—			$	756,000			$	1,645,102			$	—			$	—
Target Short-term Bonus		—				—				—				—				378,000				378,000
Pro Rata Short-term (Annual) Incentive Comp		—				—				628,614				628,614				—				—
Service-Based Unit Awards (7)		—				—				78,839				443,655				443,655				443,655
Performance-Based Unit Awards (8)		—				—				157,679				452,914				887,272				887,272
Benefits and Perquisites
Retirement Plan		—				—				—				—				—				87
ESRP		—				—				—				—				—				195
Perquisites		—				—				25,000				25,000				—				—
Health & Welfare Benefits		—				—				28,628				28,628				—				—
Total Payout:		$	—			$	—			$	1,674,760			$	3,223,913			$	1,708,927			$	1,709,209

____________________________

(1)

All scenarios include the value of severance. For Ms. Apsey, the value of the Postretirement Welfare Plan is additionally included where applicable. The Pension Benefits Table assumes that none of the NEOs are terminated prior to retirement age and that benefits are paid once retirement commences (age 58 is assumed). All other accrued pension benefits, outside of present value reductions outlined in footnote (5), and additional pension benefits upon death, have not been included in these termination scenarios but can be found in the “Pension Benefits Table”.

(2)	Upon any termination of employment, benefits that are accrued but unpaid prior to that event are paid. These benefits are assumed to be $0 in the above tables.

(3)	Change in control values include severance amounts reflecting cutbacks to the extent employer payments exceed the executive respective limits. Ms. Holloway would be subject to an excise tax on the employer payments as of the assumed change in control date; therefore, a cutback in the amount of $858,180 has been reflected.

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(4)

In the event of Mr. Jipping’s termination for death (pre-retirement), his spouse would receive half the 50% joint and survivor annuity under the traditional component of the Qualified Plan, also reduced to reflect a 90% early retirement factor that would apply at age 58 since Mr. Jipping does not have 30 years of service as of December 31, 2018. Under termination for death (pre-retirement), Ms. Apsey’s, Ms. Mason Soneral’s, Ms. Holloway’s, and Mr. Oginsky’s Qualified Plan benefits are payable immediately to the surviving spouse (if any) and ESRP benefits are payable to a designated beneficiary. The above termination scenarios do not reflect the reduction in present value of death benefits ($755,691 for Mr. Jipping under the Qualified Plan, $96 for Mr. Oginsky, and $653 for Ms. Holloway) compared to present value in the Pension Benefits Table.

(5)

The value of the Postretirement Welfare Plan benefit is included in involuntary termination not for cause and change in control scenarios since Ms. Apsey's employment agreement includes a provision for deemed satisfaction of the eligibility requirements when terminated under these scenarios. It is assumed she would commence her Postretirement Welfare Benefits at age 58. The rate at which future expected benefit payments were discounted in calculating the Postretirement Welfare Plan present values was 4.47%, the same rate used for fiscal year-end 2018 accounting disclosure of the Postretirement Welfare Plan.

(6)

The Pension Benefits Table assumes that Mr. Jipping would not be terminated before retirement age and no early retirement reduction was applied. In all termination scenarios, however, a 90% early retirement factor would apply at age 58 because Mr. Jipping has less than 30 years of service as of December 31, 2018. The above table does not reflect the reduction in the present value ($136,101 except for death) due to applying the 90% early retirement factor.

(7)

Under the 2017 Omnibus Plan, outstanding and unvested SBUs and respective dividend equivalents shall be deemed to be vested SBUs and redeemable on the Change of Control Redemption Date (as defined in the 2017 Omnibus Plan). In the case of Death or Disability (each as defined in the 2017 Omnibus Plan) termination, outstanding and unvested SBUs and respective dividend equivalents shall be deemed to be vested SBUs and redeemable on the date of the death or on the date on which the grantee’s service is terminated due to Disability. In the case of Retirement or Involuntary Termination Without Cause (each as defined in the 2017 Omnibus Plan) within one year of the grant date, outstanding and unvested SBUs and respective dividend equivalents shall be deemed to be forfeited. If Retirement or Involuntary Termination Without Cause occurs one year or more after the grant date, SBUs and respective dividend equivalents shall be deemed to have vested pro-rata based on the period served from the grant date to termination.

(8)

Under the 2017 Omnibus Plan, outstanding and unvested PBU awards and respective dividend equivalents accelerate on a prorated basis under a Change in Control (as defined in the 2017 Omnibus Plan), based on the higher of (A) 100% of the target number of PBUs in the award or (B) the actual payout percentage based on the Committee’s assessment of performance of the payment criteria from the beginning of the Payment Criteria Period for the award through the date of the Change of Control (as defined in the 2017 Omnibus Plan). In the case of Death or Disability termination, the outstanding and unvested PBU awards and respective dividend equivalents will remain outstanding and be payable on the payout date of such awards subject to the achievement of the applicable payment criteria. Values shown in the tables above are based on target performance as an estimate of potential payments. In the case of Retirement or Involuntary Termination Without Cause within one year of the award grant date, outstanding and unvested PBU awards and respective dividend equivalents shall be deemed to be forfeited. If Retirement or Involuntary Termination Without Cause occurs one year or more after the grant date, PBU awards and respective dividend equivalents shall be deemed to have vested pro-rata based on the period served from grant date to termination.

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

Pay Ratio

As required by the U.S. Congress under the Dodd-Frank Wall Street Reform and Consumer Protection Act, and the SEC under Item 402(u) of Regulation S-K, we are providing the following information about the relationship of the annual total compensation of our employees and the annual total compensation of Linda H. Apsey our CEO:

For 2018, our last completed fiscal year:

the median of the annual total compensation of all employees of the Company (other than Ms. Apsey), was $145,462; and

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the annual total compensation of Ms. Apsey as reported in the Summary Compensation Table was $3,860,052.

Based on this information, Ms. Apsey’s 2018 annual total compensation was estimated to be 27 times the median annual total compensation for all employees, other than Ms. Apsey.

Under Item 402(u), a company is permitted to identify its “median employee” once every three years if there has been no significant change to its employee population or employee compensation arrangements that would result in a significant change to its pay ratio disclosure. Since our previous year’s pay ratio disclosure there have been no such changes that would impact our previous pay ratio disclosure and, as a result, we have used the same “median employee” identified in our previous year’s disclosure.

Using our “median employee” and Ms. Apsey, we calculated the 2018 Summary Compensation Table values for each according to SEC rules.

Director Compensation

The following table provides information concerning the compensation of each person who served as a non-employee director of the Company during 2018.

Non-Employee Director Compensation Table

Name		Fees Earned or Paid in Cash ($) (1)				Stock Awards ($)				Total ($)
(a)		(b)				(c)				(h)
Robert A. Elliott		$	125,000			$	—			$	125,000
Albert Ernst		125,000				—				125,000
Rhys D. Evenden (2)		125,000				—				125,000
James P. Laurito		125,000				—				125,000
Barry V. Perry		125,000				—				125,000
Sandra E. Pierce		132,500				—				132,500
Kevin L. Prust		132,500				—				132,500
A. Douglas Rothwell		125,000				—				125,000
Thomas G. Stephens		132,500				—				132,500
Joseph L. Welch		150,000				—				150,000

____________________________

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

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

Directors who are employees of the Company do not receive separate compensation for their services as a director. All non-employee directors are compensated under our non-employee director compensation policy, pursuant to which they are paid an annual cash retainer of $125,000. In addition, we pay an additional cash retainer of $7,500 annually to the chair of each Board committee and $25,000 annually to our chairman. We do not pay per-meeting fees under the policy. Beginning in calendar year 2017, non-employee directors were and will continue to be reimbursed for their out-of-pocket expenses.

We maintain a Director Deferred Compensation Plan under which nonqualified deferred compensation is permissible. Only non-employee directors of the Company are eligible to participate in this plan. Directors are allowed to defer up to 100% of their annual board compensation. Investment earnings are based on the various investment options available under the plan, and are selected by the individual directors. Distributions will be made when the director ceases to serve on the Board and/or ceases to provide other non-employee consulting services to the Company or any Fortis entity.

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ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.

The following table sets forth certain information regarding the ownership of our common stock and Fortis’ common stock as of February 1, 2019, 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, 2019 or within 60 days thereafter through the exercise of any stock option or other right. Unless otherwise indicated, each holder has sole investment and voting power with respect to the shares set forth in the following table:

Name of Beneficial Owner	Number of Shares Beneficially Owned (#)		Percent of Class (%)		Fortis Number of shares Beneficially Owned (#)		Percent of Class (%)
Linda H. Apsey	—		—		53,889		*
Gretchen L. Holloway	—		—		5,522		*
Jon E. Jipping	—		—		120,000		*
Daniel J. Oginsky	—		—		72,621		*
Christine Mason Soneral	—		—		—		—
Robert A. Elliott	—		—		—		—
Albert Ernst	—		—		13,431 (2)		*
Rhys D. Evenden	—		—		—		—
James P. Laurito	—		—		17,346		—
Barry V. Perry	—		—		1,043,843 (3)		*
Sandra E. Pierce	—		—		—		—
Kevin L. Prust	—		—		—		—
A. Douglas Rothwell	—		—		—		—
Thomas G. Stephens	—		—		2,098		*
Joseph L. Welch	—		—		1,178,328 (1)		*
All current directors and executive officers as a group (15 persons)	—		—	%	2,507,078		*

* 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 31,410 shares owned by the spouse and children of Mr. Perry as well as 764,808 shares that may be acquired upon exercise of options that are currently exercisable or become exercisable prior to April 2, 2019.

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, 2018, there were no securities authorized for issuance under any compensation plans of ITC Holdings.

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

CERTAIN TRANSACTIONS

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

Although the Company does not have a written policy with regard to the approval of transactions between the Company and its executive officers and directors, each director and officer must annually submit a form to the General Counsel disclosing his or her conflicts or potential conflicts of interest or certifying that no such conflicts of interest exist. Throughout the year, if any transaction constituting a conflict of interest arises or circumstances otherwise change that would cause a director’s or officer’s annual conflict certification to become incorrect, the director or officer must inform the General Counsel of such circumstances. The Committee reviews existing conflicts as well as potential conflicts of interest and determines whether any further action is necessary, such as recommending to the Board whether a director or officer should be requested to offer his or her resignation. Where the Board makes a determination regarding a potential conflict of interest, a majority of the Board (excluding any interested member or members) shall decide upon an appropriate course of action. Additionally, any director or officer who has a question about whether a conflict exists must bring it to the attention of the Company’s General Counsel or Chairperson of the Committee.

Clayton Welch, Jennifer Welch, Jessica Uher and Katie Welch (each of whom is a son, daughter or daughter-in-law of Joseph L. Welch, the Company’s Chairman) were employed by us as a Senior Engineer, Fleet Manager, Manager of Corporate and Field Facilities, and Senior Accountant, respectively, during 2018 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 $554,009 during 2018.

DIRECTOR INDEPENDENCE

Based on the absence of any material relationship between them and us, other than their capacities as directors, the Board has determined that Ms. Pierce and Messrs. Elliott, Ernst, Prust, Rothwell and Stephens are “independent” as defined in the Shareholders Agreement. In addition, our Board has determined that, as the committees are currently constituted, a majority of the members of the Audit and Risk Committee are “independent” as defined in the Shareholders Agreement. None of the directors determined to be independent is or ever has been employed by us. The Company has made charitable contributions of less than $1 million each to organizations with which certain of our directors have affiliations. The Board determined that these contributions would not interfere with the exercise of independent judgment by these directors in carrying out their responsibilities.

An independent director under the Shareholders Agreement is a director who meets all of the following requirements: (a) is elected by the shareholders of Investment Holdings; (b) is designated as an independent director by the Investment Holdings’ board and Company Board, or the shareholders of Investment Holdings; (c) is not a director that is nominated by Finn Investment Pte Ltd or any successor or permitted assign thereof and appointed as a member of the Investment Holdings’ board and Company Board in accordance with the Shareholders Agreement; (d) is not and during the three years prior to being designated as an independent director has not been any of the following: (i) a director of FortisUS or any of its affiliates (other than Investment Holdings or the Company); or (ii) an officer or employee of Investment Holdings, the Company, FortisUS or any of their affiliates; and (e) would meet the definition of “independent director” under the NYSE 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 NYSE).

Mr. Elliott serves on the board of directors of UNS Energy Corporation, a wholly-owned subsidiary of FortisUS. When determining Mr. Elliott’s independence, the board and shareholders agreed to waive the requirements set forth in the definition of independent director under the Shareholders Agreement which states that a director is not

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and during the three years prior to being designated as a director of the company has not served as a director of FortisUS or any of its affiliates.

ITEM 14.      PRINCIPAL ACCOUNTANT FEES AND SERVICES.

The following table provides a summary of the aggregate fees incurred for Deloitte’s services in 2018 and 2017 :

	2018			2017
Audit fees (1)	$	1,813,000		$	1,888,000
Audit-related fees (2)	97,000			329,000
Tax fees (3)	386,000			187,000
All other fees (4)	139,000			127,000
Total fees	$	2,435,000		$	2,531,000

____________________________

(1)	Audit fees were for professional services rendered for the audit of our consolidated financial statements and internal controls and reviews of the interim consolidated financial statements included in quarterly reports and services that are normally provided by Deloitte in connection with statutory and regulatory filing engagements.

(2)	Audit-related fees were for assurance and related services that are reasonably related to the performance of the audit or review of our consolidated financial statements and are not reported under “Audit Fees.” These services include audit of our employee benefit plans, services provided in connection with securities offerings, audits in connection with acquisitions and accounting consultations.

(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 in 2017.

(4)	All other fees were for services other than the services reported above. These services included subscriptions to the Deloitte Accounting Research Tool, attendance at Deloitte sponsored conferences and labs, assessment of our ERM Program in 2017 and due diligence work in 2018.

The Audit and Risk Committee of the Board of Directors does not consider the provision of the services described above by Deloitte to be incompatible with the maintenance of Deloitte’s independence.

The Audit and Risk Committee has adopted a pre-approval policy for all audit and non-audit services pursuant to which it pre-approves all audit and non-audit services provided by the independent registered public accounting firm prior to the engagement with respect to such services. To the extent that we need an engagement for audit and/or non-audit services between Audit and Risk Committee meetings, the Audit and Risk Committee chairman is authorized by the Audit and Risk Committee to approve the required engagement on its behalf.

The Audit and Risk Committee approved all of the services performed by Deloitte in 2018 pursuant to the pre-approval policy.

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PART IV

ITEM 15.      EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.

(a)	(1)	Financial Statements:
		Management’s Report on Internal Control over Financial Reporting
		Report of Independent Registered Public Accounting Firm
		Consolidated Statements of Financial Position as of December 31, 2018 and 2017
		Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2018, 2017 and 2016
		Consolidated Statements of Changes in Stockholder's Equity for the Years Ended December 31, 2018, 2017 and 2016
		Consolidated Statements of Cash Flows for the Years Ended December 31, 2018, 2017 and 2016
		Notes to Consolidated Financial Statements
	(2)	Financial Statement Schedules
		Schedule I — Condensed Financial Information of Registrant
		All other schedules for which provision is made in Regulation S-X either (i) are not required under the related instructions or are inapplicable and, therefore, have been omitted, or (ii) the information required is included in the consolidated financial statements or the notes thereto that are a part hereof.
(b)		Exhibit Listing

The following exhibits are filed as part of this report or filed previously and incorporated by reference to the filing indicated. Our SEC file number is 001-32576.

Exhibit No.			Description of Exhibit
2.1			Agreement and Plan of Merger, dated as of February 9, 2016, among FortisUS Inc., Element Acquisition Sub Inc., Fortis Inc., and ITC Holdings Corp. (filed with Registrant’s Form 8-K on February 11, 2016)
3.1			Restated Articles of Incorporation of ITC Holdings Corp. (filed with Registrant’s Form 10-Q for the quarter ended September 30, 2016)
3.2			Sixth Amended and Restated Bylaws of ITC Holdings Corp (filed with Registrant’s Form 8-K on October 12, 2016)
4.3			Indenture, dated as of July 16, 2003, between ITC Holdings Corp. and BNY Midwest Trust Company, as trustee (filed with Registrant’s Registration Statement on Form S-1, as amended, Reg. No. 333-123657)
4.5			First Mortgage and Deed of Trust, dated as of July 15, 2003, between International Transmission Company and BNY Midwest Trust Company, as trustee (filed with Registrant’s Registration Statement on Form S-1, as amended, Reg. No. 333-123657)
4.6			First Supplemental Indenture, dated as of July 15, 2003, supplementing the First Mortgage and Deed of Trust dated as of July 15, 2003, between International Transmission Company and BNY Midwest Trust Company, as trustee (filed with Registrant’s Registration Statement on Form S-1, as amended, Reg. No. 333-123657)
4.7			Second Supplemental Indenture, dated as of July 15, 2003, supplementing the First Mortgage and Deed of Trust dated as of July 15, 2003, between International Transmission Company and BNY Midwest Trust Company, as trustee (filed with Registrant’s Registration Statement on Form S-1, as amended, Reg. No. 333-123657)
4.8			Amendment to Second Supplemental Indenture, dated as of January 19, 2005, between International Transmission Company and BNY Midwest Trust Company, as trustee (filed with Registrant’s Registration Statement on Form S-1, as amended, Reg. No. 333-123657)
4.9			Second Amendment to Second Supplemental Indenture, dated as of March 24, 2006, between International Transmission Company and The Bank of New York Trust Company, N.A. (as successor to BNY Midwest Trust Company), as trustee (filed with Registrant’s Form 8-K on March 30, 2006)
4.10			Third Supplemental Indenture, dated as of March 28, 2006, supplementing the First Mortgage and Deed of Trust dated as of July 15, 2003, between International Transmission Company and BNY Midwest Trust Company, as trustee (filed with Registrant’s Form 8-K on March 30, 2006)

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Exhibit No.		Description of Exhibit

4.12			Second Supplemental Indenture, dated as of October 10, 2006, supplemental to the Indenture dated as of July 16, 2003, between the Registrant and The Bank of New York Trust Company, N.A., (as successor to BNY Midwest Trust Company, as trustee) (filed with Registrant’s Form 8-K on October 10, 2006)
4.14			First Mortgage Indenture between Michigan Electric Transmission Company, LLC and JPMorgan Chase Bank, dated as of December 10, 2003 (filed with Registrant’s Form 10-Q for the quarter ended September 30, 2006)
4.17			ITC Holdings Corp. Note Purchase Agreement, dated as of September 20, 2007 (filed with Registrant’s Form 10-Q for the quarter ended September 30, 2007)
4.18			Third Supplemental Indenture, dated as of January 24, 2008, supplemental to the Indenture dated as of July 16, 2003, between the Registrant and The Bank of New York Trust Company, N.A. (as successor to BNY Midwest Trust Company), as trustee (filed with Registrant’s Form 8-K on January 25, 2008)
4.19			First Mortgage and Deed of Trust, dated as of January 14, 2008, between ITC Midwest LLC and The Bank of New York Trust Company, N.A., as trustee (filed with Registrant’s Form 8-K on February 1, 2008)
4.20			First Supplemental Indenture, dated as of January 14, 2008, supplemental to the First Mortgage Indenture between ITC Midwest LLC and The Bank of New York Trust Company, N.A., as trustee, First Mortgage and Deed of Trust, dated as of January 14, 2008 (filed with Registrant’s Form 8-K on February 1, 2008)
4.23			Second Supplemental Indenture, dated as of December 15, 2008, between ITC Midwest LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Trust Company, N.A.), as trustee, to the First Mortgage and Deed of Trust, dated as of January 14, 2008 (filed with Registrant’s Form 8-K on December 23, 2008)
4.24			Third Supplemental Indenture, dated as of November 25, 2008, between METC and The Bank of New York Mellon Trust Company, N.A. (as successor to JPMorgan Chase Bank, N.A.), as trustee, to the First Mortgage Indenture between Michigan Electric Transmission Company, LLC and JPMorgan Chase Bank, dated as of December 10, 2003 (filed with Registrant’s Form 8-K on December 23, 2008)
4.25			Fourth Supplemental Indenture, dated as of December 11, 2009, between ITC Holdings Corp. and The Bank of New York Mellon Trust Company, N.A. (f.k.a. The Bank of New York Trust Company, N.A., as successor to BNY Midwest Trust Company), as trustee (filed with Registrant’s Form 8-K on December 14, 2009)
4.26			Fourth Supplemental Indenture, dated as of December 10, 2009, between ITC Midwest LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Trust Company, N.A.), as trustee (filed with Registrant’s Form 8-K on December 17, 2009)
4.27			Fifth Supplemental Indenture, dated as of April 20, 2010, between Michigan Electric Transmission Company, LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to JPMorgan Chase Bank), as trustee (filed with Registrant’s Form 8-K on May 10, 2010)
4.28			Third Supplemental Indenture, dated as of December 15, 2008, between ITC Midwest LLC and The Bank of New York Mellon Trust Company, N.A. (The Bank of New York Trust Company, N.A.), as trustee (filed with Registrant’s Form 10-Q for the quarter ended June 30, 2011)
4.29			Fifth Supplemental Indenture, dated as of July 15, 2011, between ITC Midwest LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Trust Company, N.A.), as trustee (filed with Registrant’s Form 10-Q for the quarter ended June 30, 2011)
4.30			Sixth Supplemental Indenture, dated as of November 29, 2011, between ITC Midwest LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Trust Company, N.A.), as trustee (filed with Registrant’s Form 8-K on December 1, 2011)
4.31			Sixth Supplemental Indenture, dated as of October 5, 2012, between Michigan Electric Transmission Company, LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to JPMorgan Chase Bank), as trustee (filed with Registrant’s Form 8-K on October 29, 2012)
4.32			Seventh Supplemental Indenture, dated as of March 18, 2013, between ITC Midwest LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Trust Company, N.A.), as trustee (filed with Registrant’s Form 8-K on April 8, 2013)
4.33			Indenture, dated as of April 18, 2013, between ITC Holdings Corp. and Wells Fargo Bank, National Association, as trustee (including form of note) (filed with Registrant’s Form S-3 on April 18, 2013)
4.34			First Supplemental Indenture, dated as of July 3, 2013, between ITC Holdings Corp. and Wells Fargo Bank, National Association, as trustee (including forms of notes) (filed with Registrant’s Form 8-K on July 3, 2013)

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Exhibit No.		Description of Exhibit

4.35			Fifth Supplemental Indenture, dated as of August 7, 2013, between International Transmission Company and The Bank of New York Mellon Trust Company, N.A. (as successor to BNY Midwest Trust Company), as trustee (including form of bonds) (filed with Registrant’s Form 8-K on August 16, 2013)
4.36			Fifth Supplemental Indenture, dated May 16, 2014, between ITC Holdings Corp. and The Bank of New York Mellon Trust Company, N.A. (f.k.a. The Bank of New York Trust Company, N.A., as successor to BNY Midwest Trust Company), as Trustee (filed with Registrant’s Form 8-K on May 16, 2014)
4.38			Second Supplemental Indenture, dated as of June 4, 2014 between ITC Holdings Corp. and Wells Fargo Bank, National Association, as trustee, together with form of 3.65% Senior Note due 2024 (filed with Registrant’s Form 8-K on June 4, 2014)
4.39			Sixth Supplemental Indenture, dated as of May 23, 2014, between International Transmission Company and The Bank of New York Mellon Trust Company, N.A. (as successor to BNY Midwest Trust Company), as trustee (filed with Registrant’s Form 8-K on June 10, 2014)
4.40			First Mortgage and Deed of Trust, dated as of November 12, 2014, between ITC Great Plains, LLC and Wells Fargo Bank, National Association, as trustee (filed with Registrant’s Form 8-K on November 26, 2014)
4.41			First Supplemental Indenture, dated as of November 12, 2014, between ITC Great Plains, LLC and Wells Fargo Bank, National Association, as trustee (filed with Registrant’s Form 8-K on November 26, 2014)
4.42			Seventh Supplemental Indenture, dated as of December 5, 2014, between Michigan Electric Transmission Company, LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to JPMorgan Chase Bank), as trustee (filed with Registrant’s Form 8-K on December 22, 2014)
4.43			Eighth Supplemental Indenture, dated as of March 18, 2015, between ITC Midwest LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Trust Company, N.A.), as trustee (filed with Registrant’s Form 8-K on April 8, 2015)
4.44			Eighth Supplemental Indenture, dated as of March 31, 2016, between Michigan Electric Transmission Company, LLC and Bank of New York Mellon Trust Company, N.A. (as successor to JPMorgan Chase Bank), as trustee (filed with Registrant’s Form 8-K on April 26, 2016)
4.45			Third Supplemental Indenture, dated as of July 5, 2016, between ITC Holdings Corp. and Wells Fargo Bank, National Association, as trustee, together with form of 3.25% Note due 2026 (filed with Registrant’s Form 8-K on July 5, 2016)
4.46			Ninth Supplemental Indenture, dated as of March 15, 2017, between ITC Midwest LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Trust Company, N.A.), as trustee (filed with Registrant’s Form 8-K on April 18, 2017)
4.47			Fourth Supplemental Indenture, dated as of November 14, 2017 between ITC Holdings Corp. and Wells Fargo Bank, National Association, as trustee (with Form of 2.700% Notes due 2022 and Form of 3.350% Notes due 2027) (filed with Registrant’s Form 8-K on November 15, 2017)
4.48			Seventh Supplemental Indenture, dated as of March 14, 2018, between International Transmission Company and The Bank of New York Mellon Trust Company, N.A. (as successor to BNY Midwest Trust Company), as trustee (filed with Registrant’s Form 8-K on March 29, 2018)
4.49			Tenth Supplemental Indenture, dated as of September 28, 2018, between ITC Midwest LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Trust Company, N.A.) as trustee (filed with Registrant’s Form 8-K on November 2, 2018)
4.50			Ninth Supplemental Indenture, dated as of November 28, 2018, between Michigan Electric Transmission Company, LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to JP Morgan Chase Bank), as trustee (filed with Registrant’s Form 8-K on January 15, 2019)
*10.27			Deferred Compensation Plan (filed with Registrant’s Registration Statement on Form S-1, as amended, Reg. No. 333-123657)
10.51			Form of Amended and Restated Easement Agreement between Consumers Energy Company and Michigan Electric Transmission Company (filed with Registrant’s Form 10-Q for the quarter ended September 30, 2006)
*10.81			Executive Supplemental Retirement Plan (filed with Registrant’s 2008 Form 10-K)
*10.109			Employment Agreement between ITC Holdings Corp. and Linda H. Blair, effective as of December 21, 2012 (filed with Registrant’s Form 8-K on December 26, 2012)

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Exhibit No.		Description of Exhibit

*10.110			Employment Agreement between ITC Holdings Corp. and Jon E. Jipping, effective as of December 21, 2012 (filed with Registrant’s Form 8-K on December 26, 2012)
*10.111			Employment Agreement between ITC Holdings Corp. and Daniel J. Oginsky, effective as of December 21, 2012 (filed with Registrant’s Form 8-K on December 26, 2012)
*10.120			First Amendment to Executive Supplemental Retirement Plan, dated as of May 16, 2013 (filed with Registrant’s Form 10-Q for the quarter ended June 30, 2013)
*10.122			Recoupment Policy and Related Consent, effective January 1, 2014 (filed with Registrant’s Form 8-K on December 2, 2013)
*10.150			Employment Agreement between ITC Holdings Corp. and Christine Mason Soneral, effective as of February 3, 2015 (filed with Registrant’s Form 10-Q for the quarter ended June 30, 2015)
*10.168			Letter Agreement, dated as of October 14, 2016, between ITC Holdings Corp. and Linda H. Blair (filed with Registrant’s Form 8-K on October 12, 2016)
*10.172			Employment Agreement between ITC Holdings Corp. and Gretchen L. Holloway, effective as of February 3, 2015. (filed with Registrant’s 2016 Form 10-K)
*10.173			Amended Employment Agreement, dated as of October 12, 2016 between ITC Holdings Corp. and Christine Mason Soneral (filed with Registrant’s 2016 Form 10-K)
*10.176			2017 Omnibus Plan, effective February 27, 2017 (filed with Registrant’s Form 10-Q for the quarter ended March 31, 2017)
*10.177			Summary of 2017 Annual Incentive Plan (filed with Registrant’s Form 10-Q for the quarter ended March 31, 2017)
*10.178			Form of Service-Based Unit Award Agreement under 2017 Omnibus Plan (February 2017) (filed with Registrant’s Form 10-Q for the quarter ended March 31, 2017)
*10.179			Form of Performance-Based Unit Award Agreement under 2017 Omnibus Plan (February 2017) (filed with Registrant’s Form 10-Q for the quarter ended March 31, 2017)
10.181			Term Loan Credit Agreement, dated as of March 23, 2017, among International Transmission Company, the various financial institutions and other persons from time to time parties thereto as lenders and PNC Bank, National Association, as administrative agent (filed with Registrant’s Form 8-K on March 27, 2017)
10.182			Amendment to 2017 Omnibus Plan, dated as of July 10, 2017 (filed with Registrant’s Form 10-Q for the quarter ended June 30, 2017)
10.183			ITC Holdings Corp. Director Deferred Compensation Plan, effective March 1, 2017 (filed with Registrant’s Form 10-Q for the quarter ended June 30, 2017)
10.184			ITC Holdings Revolving Credit Agreement, dated as of October 23, 2017, among ITC Holdings Corp., with the banks, financial institutions and other institutional lenders listed on the respective signature pages thereof, JPMorgan Chase Bank, N.A., as administrative agent for the Lenders, JPMorgan Chase Bank, N.A., Barclays Bank PLC, Wells Fargo Securities, LLC, The Bank of Nova Scotia and Mizuho Bank, Ltd., as joint lead arrangers and joint bookrunners, Barclays Bank PLC and Wells Fargo Bank, National Association, as co-syndication agents and The Bank of Nova Scotia and Mizuho Bank, Ltd. as co-documentation agents (filed with Registrant’s Form 8-K on October 23, 2017)
10.185			ITCTransmission Revolving Credit Agreement, dated as of October 23, 2017, among International Transmission Company, with the banks, financial institutions and other institutional lenders listed on the respective signature pages thereof, JPMorgan Chase Bank, N.A., as administrative agent for the Lenders, JPMorgan Chase Bank, N.A., Barclays Bank PLC, Wells Fargo Securities, LLC, The Bank of Nova Scotia and Mizuho Bank, Ltd., as joint lead arrangers and joint bookrunners, Barclays Bank PLC and Wells Fargo Bank, National Association, as co-syndication agents and The Bank of Nova Scotia and Mizuho Bank, Ltd. as co-documentation agents (filed with Registrant’s Form 8-K on October 23, 2017)
10.186			METC Revolving Credit Agreement, dated as of October 23, 2017, among Michigan Electric Transmission Company, LLC, with the banks, financial institutions and other institutional lenders listed on the respective signature pages thereof, JPMorgan Chase Bank, N.A., as administrative agent for the Lenders, JPMorgan Chase Bank, N.A., Barclays Bank PLC, Wells Fargo Securities, LLC, The Bank of Nova Scotia and Mizuho Bank, Ltd., as joint lead arrangers and joint bookrunners, Barclays Bank PLC and Wells Fargo Bank, National Association, as co-syndication agents and The Bank of Nova Scotia and Mizuho Bank, Ltd. as co-documentation agents (filed with Registrant’s Form 8-K on October 23, 2017)

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Exhibit No.		Description of Exhibit

10.187			ITC Midwest Revolving Credit Agreement, dated as of October 23, 2017, among ITC Midwest LLC, with the banks, financial institutions and other institutional lenders listed on the respective signature pages thereof, JPMorgan Chase Bank, N.A., as administrative agent for the Lenders, JPMorgan Chase Bank, N.A., Barclays Bank PLC, Wells Fargo Securities, LLC, The Bank of Nova Scotia and Mizuho Bank, Ltd., as joint lead arrangers and joint bookrunners, Barclays Bank PLC and Wells Fargo Bank, National Association, as co-syndication agents and The Bank of Nova Scotia and Mizuho Bank, Ltd. as co-documentation agents (filed with Registrant’s Form 8-K on October 23, 2017)
10.188			ITC Great Plains Revolving Credit Agreement, dated as of October 23, 2017, among ITC Great Plains, LLC, with the banks, financial institutions and other institutional lenders listed on the respective signature pages thereof, JPMorgan Chase Bank, N.A., as administrative agent for the Lenders, JPMorgan Chase Bank, N.A., Barclays Bank PLC, Wells Fargo Securities, LLC, The Bank of Nova Scotia and Mizuho Bank, Ltd., as joint lead arrangers and joint bookrunners, Barclays Bank PLC and Wells Fargo Bank, National Association, as co-syndication agents and The Bank of Nova Scotia and Mizuho Bank, Ltd. as co-documentation agents (filed with Registrant’s Form 8-K on October 23, 2017)
10.189			Registration Rights Agreement, dated November 14, 2017 between ITC Holdings Corp., Barclays Capital Inc., J.P. Morgan Securities LLC, Morgan Stanley & Co. LLC and Wells Fargo Securities, LLC, on their own behalf and as representatives of each of the other initial purchasers named therein (filed with Registrant’s Form 8-K on November 15, 2017)
10.190			International Transmission Company Executive Deferred Compensation Plan, effective January 1, 2019
10.191			ITC Holdings Corp. Director Deferred Compensation Plan, effective January 1, 2019
21			List of Subsidiaries
31.1			Certification of Chief Executive Officer pursuant to Rule 13a-14 of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2			Certification of Chief Financial Officer pursuant to Rule 13a-14 of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32			Certification 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.

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SCHEDULE I — Condensed Financial Information of Registrant

ITC HOLDINGS CORP.

CONDENSED STATEMENTS OF FINANCIAL POSITION (PARENT COMPANY ONLY)

	December 31,
(In millions, except share data)	2018				2017
ASSETS
Current assets
Cash and cash equivalents	$	3			$	60
Accounts receivable from subsidiaries	26				21
Intercompany tax receivable from subsidiaries	15				2
Income tax receivable	1				15
Prepaid and other current assets	1				1
Total current assets	46				99
Other assets
Investment in subsidiaries	4,733				4,461
Deferred income taxes	104				141
Other	90				96
Total other assets	4,927				4,698
TOTAL ASSETS	$	4,973			$	4,797
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities
Accounts payable	$	5			$	3
Accrued compensation	30				28
Accrued interest	26				33
Other	7				5
Total current liabilities	68				69
Accrued pension and postretirement liabilities	68				74
Other	19				6
Long-term debt (net of deferred financing fees and discount of $20 and $22, respectively)	2,767				2,728
STOCKHOLDER’S EQUITY
Common stock, without par value, 235,000,000 shares authorized as of December 31, 2018, and 224,203,112 shares issued and outstanding at December 31, 2018 and 2017	892				892
Retained earnings	1,155				1,026
Accumulated other comprehensive income	4				2
Total stockholder’s equity	2,051				1,920
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	4,973			$	4,797

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

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SCHEDULE I — Condensed Financial Information of Registrant

ITC HOLDINGS CORP.

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (PARENT COMPANY ONLY)

	Year Ended December 31,
(In millions)	2018				2017				2016
Other income (expense), net	$	1			$	2			$	—
General and administrative expense	(7		)		(11		)		(121		)
Taxes other than income taxes	—				(2		)		—
Interest expense	(114		)		(120		)		(113		)
LOSS BEFORE INCOME TAXES	(120		)		(131		)		(234		)
INCOME TAX BENEFIT	(30		)		(6		)		(122		)
LOSS AFTER TAXES	(90		)		(125		)		(112		)
EQUITY IN SUBSIDIARIES’ NET EARNINGS	420				444				358
NET INCOME	330				319				246
OTHER COMPREHENSIVE INCOME (LOSS)
Derivative instruments (net of tax of less than $1 for the year ended December 31, 2018 and $3 for the year ended December 31, 2016)	1				—				(2		)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX	1				—				(2		)
TOTAL COMPREHENSIVE INCOME	$	331			$	319			$	244

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

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SCHEDULE I — Condensed Financial Information of Registrant

ITC HOLDINGS CORP.

CONDENSED STATEMENTS OF CASH FLOWS (PARENT COMPANY ONLY)

	Year Ended December 31,
(In millions)	2018				2017				2016
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	330			$	319			$	246
Adjustments to reconcile net income to net cash used in operating activities:
Equity in subsidiaries' earnings	(420		)		(444		)		(358		)
Dividends from subsidiaries	26				3				10
Deferred and other income taxes	(23		)		67				(69		)
Net intercompany tax payments from (to) subsidiaries	59				(13		)		(72		)
Expense for the accelerated vesting of share-based awards associated with the Merger	—				—				41
Other	2				5				25
Changes in assets and liabilities, exclusive of changes shown separately:
Accounts receivable from subsidiaries	(4		)		(4		)		22
Intercompany tax receivable from subsidiaries	(13		)		2				—
Income tax receivable	14				2				(17		)
Intercompany tax payable to subsidiaries	—				(72		)		85
Accrued compensation	2				14				(10		)
Accrued taxes	2				—				(35		)
Other current and non-current assets and liabilities, net	11				—				9
Net cash used in operating activities	(14		)		(121		)		(123		)
CASH FLOWS FROM INVESTING ACTIVITIES
Equity contributions to subsidiaries	(202		)		(148		)		(87		)
Return of capital from subsidiaries	324				296				274
Other	(1		)		(9		)		(9		)
Net cash provided by investing activities	121				139				178
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt, net of discount	—				999				399
Borrowings under revolving credit agreement	37				97				126
Borrowings under term loan credit agreement	—				200				—
Net issuance of commercial paper, net of discount	—				(148		)		48
Retirement of long-term debt — including extinguishment of debt costs	—				(437		)		(139		)
Repayments of revolving credit agreement	—				(170		)		(191		)
Repayments of term loan credit agreements	—				(200		)		(161		)
Dividends on common stock	—				—				(90		)
Dividends to ITC Investment Holdings Inc.	(200		)		(300		)		(33		)
Settlement of share-based compensation awards associated with the Merger — including cost of accelerated share-based awards	—				—				(137		)
Contribution from ITC Investment Holdings Inc. for the settlement of share-based awards associated with the Merger	—				—				137
Other	(1		)		(2		)		(18		)
Net cash (used in) provided by financing activities	(164		)		39				(59		)
NET (DECREASE) INCREASE IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH	(57		)		57				(4		)
CASH, CASH EQUIVALENTS AND RESTRICTED CASH — Beginning of period	61				4				8
CASH, CASH EQUIVALENTS AND RESTRICTED CASH — End of period	$	4			$	61			$	4

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

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SCHEDULE I — Condensed Financial Information of Registrant

ITC HOLDINGS CORP.

NOTES TO CONDENSED FINANCIAL STATEMENTS (PARENT COMPANY ONLY)

1.     GENERAL

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

As a holding company with no business operations, ITC Holdings’ assets consist primarily of investments in our subsidiaries. ITC Holdings’ material cash inflows are only from dividends and other payments received from our subsidiaries, the proceeds raised from the sale of debt securities, issuances under our commercial paper program and borrowings under our revolving credit agreement. ITC Holdings may not be able to access cash generated by our subsidiaries in order to fulfill cash commitments. The ability of our subsidiaries to make dividend and other payments to us is subject to the availability of funds after taking into account their respective funding requirements, the terms of their respective indebtedness, the regulations of the FERC under the FPA and applicable state laws. In addition, there are practical limitations on using the net assets of each of our Regulated Operating Subsidiaries as of December 31, 2018 for dividends based on management's intent to maintain the FERC-approved capital structure targeting 60% equity and 40% debt for each of our Regulated Operating Subsidiaries. These net assets are included in Schedule I as the line-item “Investments in subsidiaries.” Each of our subsidiaries, however, is legally distinct from us and has no obligation, contingent or otherwise, to make funds available to us.

2.     DEBT

As of December 31, 2018 , the maturities of our debt outstanding were as follows:

(In millions)
2019	$	—
2020	200
2021	—
2022	537
2023	250
2024 and thereafter	1,800
Total	$	2,787

Refer to Note 10 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 $2,764 million  and $2,908 million at December 31, 2018 and 2017 , respectively. The total book value of the ITC Holdings Senior Notes, net of discount and deferred financing fees, was $2,730 million and $2,728 million at December 31, 2018 and 2017 , respectively. At December 31, 2018 , we had $37 million outstanding under our revolving credit agreements, which are variable rate loans compared to no amounts outstanding as of December 31, 2017 . 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 13 to the consolidated financial statements. At December 31, 2018 and 2017 ITC Holdings had no commercial paper issued and outstanding under the commercial paper program. Due to the short-term nature of these financial instruments, the carrying value approximates fair value.

Covenants

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

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covenants require us to meet certain financial ratios, such as maintaining certain debt to capitalization ratios and certain funds from operations to debt levels. At December 31, 2018 , we were not in violation of any debt covenant.

3.     RELATED-PARTY TRANSACTIONS

Our related-party transactions during 2018, 2017 and 2016 were as follows:

	Year Ended December 31,
(In millions)	2018				2017				2016
Equity contributions to subsidiaries	$	202			$	148			$	87
Dividends from subsidiaries (a)	26				3				10
Return of capital from subsidiaries (a)	324				296				274
Net income tax payments (to) from: (b)
ITCTransmission	$	39			$	4			$	(28	)
METC	7				1				(14		)
ITC Midwest	3				5				(34		)
ITC Great Plains	9				11				4
ITC Interconnection	1				1				—
Other (c)	—				(35		)		—

____________________________

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

(b)

The net income tax payments were pursuant to intercompany tax sharing arrangements, and the total of these tax payments is presented as a net cash outflow or inflow from operating activities in the condensed parent company statements of cash flows. Other reconciling items between the parent company and the consolidated tax liabilities are presented as deferred and other income taxes in the adjustments to reconcile net income to net cash provided by operating activities. Additionally, ITC Holdings paid its subsidiaries for NOLs utilized by the consolidated group.

(c)	Includes all of our non-regulated subsidiaries.

Net Intercompany Receivables and Payables

We may incur charges from our subsidiaries for general corporate expenses incurred. In addition, we may perform additional services for, or receive additional services from our subsidiaries. These transactions are in the normal course of business and payments for these services are settled through accounts receivable and accounts payable, as necessary. We generally settle our intercompany balances with our affiliates on a net basis monthly.

Intercompany Tax Sharing Arrangement

As discussed in Note 1 to the condensed financial statements of the parent company, we are a holding company with no business operations. We file consolidated income tax returns that include our affiliates, which are taxed as a corporation for federal and Michigan income tax purposes. We operate under an intercompany tax sharing arrangement with our subsidiaries and as a result may receive or pay federal and state income tax based on their stand-alone company tax positions.

Retirement Benefits

We are the plan sponsor for a pension plan, other postretirement plans and a defined contribution plan. The benefits-related expenses recorded by our affiliates result from the inclusion of benefit costs as a component of the total charge for services performed by our employees under the cost assignment and allocation methods used by us and our subsidiaries.

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4.    SUPPLEMENTAL FINANCIAL INFORMATION

Reconciliation of Cash, Cash Equivalents and Restricted Cash

The following table provides a reconciliation of cash, cash equivalents and restricted cash reported on the condensed statements of financial position that sum to the total of the same such amounts shown in the condensed statements of cash flows:

	December 31,
(In millions)	2018				2017				2016				2015
Cash and cash equivalents	$	3			$	60			$	4			$	8
Restricted cash included in:
Other non-current assets	1				1				—				—
Total cash, cash equivalents and restricted cash	$	4			$	61			$	4			$	8

Restricted cash included in other non-current assets primarily represents cash on deposit to pay for vegetation management, land easements and land purchases for the purpose of transmission line construction.

Supplementary Cash Flows Information

	Year Ended December 31,
(In millions)	2018				2017				2016
Supplementary cash flows information:
Interest paid	$	117			$	115			$	112
Income taxes paid	—				—				23
Income tax refunds received (a)	13				1				129
Supplementary non-cash investing and financing activities:
Equity transfers from subsidiaries	—				(2		)		—

____________________________

(a)	Amount for the year ended December 31, 2016 includes the income tax refund of $128 million received from the IRS in August 2016, which resulted from the election of bonus depreciation.

ITEM 16.      FORM 10-K SUMMARY.

Not applicable.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized in the City of Novi, State of Michigan, on February 14, 2019 .

ITC HOLDINGS CORP.
By:	/s/ LINDA H. APSEY
	Linda H. Apsey
	President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant and in the capacities and on the dates indicated:

Signature	Title	Date
/s/ LINDA H. APSEY	President and Chief Executive	February 14, 2019
Linda H. Apsey	Officer (principal executive officer)
/s/ GRETCHEN L. HOLLOWAY	Senior Vice President and Chief Financial Officer	February 14, 2019
Gretchen L. Holloway	(principal financial and accounting officer)
/s/ JOSEPH L. WELCH	Director and Chairman	February 14, 2019
Joseph L. Welch
/s/ ROBERT A. ELLIOTT	Director	February 14, 2019
Robert A. Elliott
/s/ ALBERT ERNST	Director	February 14, 2019
Albert Ernst
/s/ RHYS D. EVENDEN	Director	February 14, 2019
Rhys D. Evenden
/s/ JAMES P. LAURITO	Director	February 14, 2019
James P. Laurito
/s/ BARRY V. PERRY	Director	February 14, 2019
Barry V. Perry
/s/ SANDRA E. PIERCE	Director	February 14, 2019
Sandra E. Pierce
/s/ KEVIN L. PRUST	Director	February 14, 2019
Kevin L. Prust
/s/ A. DOUGLAS ROTHWELL	Director	February 14, 2019
A. Douglas Rothwell
/s/ THOMAS G. STEPHENS	Director	February 14, 2019
Thomas G. Stephens

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