ITC Holdings Corp. - FORM 10-K

Attached files

file	filename
EX-32 - CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 - SECTION 906 OF SOX - ITC Holdings Corp.	itc20171231ex_32.htm
EX-31.2 - CERTIFICATION OF CFO PURSUANT TO RULE 13A-14 - SECTION 302 OF SOX - ITC Holdings Corp.	itc20171231ex_312.htm
EX-31.1 - CERTIFICATION OF CEO PURSUANT TO RULE 13A-14 - SECTION 302 OF SOX - ITC Holdings Corp.	itc20171231ex_311.htm
EX-21 - LIST OF SUBSIDIARIES - ITC Holdings Corp.	itc20171231ex_21.htm
EX-12.1 - RATIO OF EARNINGS TO FIXED CHARGES - ITC Holdings Corp.	itc20171231ex_121.htm

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)



þ	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended December 31, 2017



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

Commission File Number: 001-32576

ITC HOLDINGS CORP.

(Exact Name of Registrant as Specified in Its Charter)



Michigan (State or Other Jurisdiction of Incorporation or Organization)		32-0058047 (I.R.S. Employer Identification No.)

27175 Energy Way

Novi, Michigan 48377

(Address Of Principal Executive Offices, Including Zip Code)

(248) 946-3000

(Registrant’s Telephone Number, Including Area Code)

Securities registered pursuant to Section 12(b) of the Act:



Title of Each Class Common stock, without par value		Name of Each Exchange on Which Registered None

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act of 1933. Yes o No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934. Yes þ No o

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes o No þ

*(Note: The Registrant is a voluntary filer and has not been subject to the filing requirements under Section 13 or 15(d) of the Securities Exchange Act of 1934 for the preceding 12 months.)

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o

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

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



Large accelerated filer o	Accelerated filer o	Non-accelerated filer þ	Smaller Reporting Company o	Emerging growth company o
		(Do not check if a smaller reporting company)

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

The aggregate market value of the registrant’s common stock held by non-affiliates on June 30, 2017 was $0.

All shares of outstanding common stock of ITC Holdings Corp. are held by its parent company, ITC Investment Holdings Inc., which is an indirect subsidiary of Fortis Inc. There were 224,203,112 shares of common stock, no par value, outstanding as of February 14, 2018.

DOCUMENTS INCORPORATED BY REFERENCE

None

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ITC Holdings Corp.

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

INDEX



		Page
PART I		7
Item 1.	Business	7
Item 1A.	Risk Factors	15
Item 1B.	Unresolved Staff Comments	22
Item 2.	Properties	22
Item 3.	Legal Proceedings	24
Item 4.	Mine Safety Disclosures	24

PART II		24
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	24
Item 6.	Selected Financial Data	25
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	26
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	44
Item 8.	Financial Statements and Supplementary Data	46
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	94
Item 9A.	Controls and Procedures	94
Item 9B.	Other Information	94

PART III		94
Item 10.	Directors, Executive Officers and Corporate Governance	94
Item 11.	Executive Compensation	98
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	126
Item 13.	Certain Relationships and Related Transactions, and Director Independence	127
Item 14.	Principal Accountant Fees and Services	128

PART IV		129
Item 15.	Exhibits and Financial Statement Schedules	129
Item 16.	Form 10-K Summary	142
Signatures		142

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DEFINITIONS

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

ITC Holdings Corp. and its subsidiaries


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


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


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


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


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


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


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


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


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


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


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

Other definitions


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


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


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


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


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


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


•	“DCF” are references to discounted cash flow;


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


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


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


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


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

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


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


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


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


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


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


•	“Fortis” are references to Fortis Inc.;


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


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


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


•	“Generator Interconnection Agreement” are references to the Amended and Restated Generator Interconnection Agreement entered into by Consumers Energy and METC dated as of April 29, 2002 and most recently amended effective as of October 1, 2016;


•	“GIC” are references to GIC Private Limited;


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


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


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


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


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


•	“ISO” are references to Independent System Operators;


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


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


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


•	“LGIA” are references to the Large Generator Interconnection Agreement entered into by ITC Midwest, IP&L, and MISO dated as of December 20, 2007 and amended as of August 6, 2013;


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


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


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


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


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


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


•	“Mid-Kansas Agreement” are references to an Amended and Restated Maintenance Agreement entered into by Mid-Kansas and ITC Great Plains dated as of August 24, 2010, and most recently amended effective as of June 1, 2015;

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


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


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


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


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


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


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


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


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


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


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


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


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


•	“PCBs” are references to polychlorinated biphenyls;


•	“ROE” are references to return of equity;


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


•	“RTO” are references to Regional Transmission Organizations;


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


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


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


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


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


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


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


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


•	“TO” are references to transmission owners; and


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

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EXPLANATORY NOTE

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

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

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

The Merger

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

Development of Business

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

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

Development Projects

Through our development activities, we are actively pursuing projects in North America to upgrade the existing transmission grid and regional transmission facilities, primarily to improve overall grid reliability, reduce transmission constraints, enhance competitive wholesale electricity markets and facilitate interconnections of new generating resources, including wind generation and other renewable resources necessary to achieve state and federal policy goals. We are also actively pursuing energy storage and contracted transmission projects.

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Segments

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

Operations

As transmission-only companies, our Regulated Operating Subsidiaries function as conduits, allowing for power from generators to be transmitted to local distribution systems either entirely through their own systems or in conjunction with neighboring transmission systems. Third parties then transmit power through these local distribution systems to end-use consumers. The transmission of electricity by our Regulated Operating Subsidiaries is a central function to the provision of electricity to residential, commercial and industrial end-use consumers. The operations performed by our Regulated Operating Subsidiaries fall into the following categories:


•	asset planning;


•	engineering, design and construction;


•	maintenance; and


•	real time operations.

Asset Planning

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

The Asset Planning group works closely with MISO and SPP in the development of our system expansion capital plans by performing technical evaluations and detailed studies. As the regional planning authorities, MISO and SPP approve regional system improvement plans, which include projects to be constructed by their members, including our MISO Regulated Operating Subsidiaries and ITC Great Plains.

Engineering, Design and Construction

The Engineering, Design and Construction group is responsible for design, equipment specifications, maintenance plans and project engineering for capital, operation and maintenance work. We work with outside contractors to perform various aspects of our engineering, design and construction, but retain internal technical experts who have experience with respect to the key elements of the transmission system such as substations, lines, equipment and protective relaying systems.

Maintenance

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

Real Time Operations

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

Local Balancing Authority Operator — Under the functional control of MISO, ITCTransmission and METC operate their electric transmission systems as a combined LBA area, known as MECS. From our operations facility in Novi, Michigan, our employees perform the LBA functions as outlined in MISO’s Balancing Authority Agreement. These

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

Operating Contracts

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

ITCTransmission

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

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

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

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

METC

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

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

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

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

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

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

ITC Midwest

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

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

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

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

ITC Great Plains

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

ITC Interconnection

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

Regulatory Environment

Many regulators and public policy makers support the need for further investment in the transmission grid. The growth and changing mix of electricity generation, wholesale power sales and consumption combined with historically inadequate transmission investment have resulted in significant transmission constraints across the United States and increased stress on aging equipment. These problems will continue without increased investment in transmission infrastructure. Transmission system investments can also increase system reliability and reduce the frequency of power outages. Such investments can reduce transmission constraints and improve access to lower cost generation resources, resulting in a lower overall cost of delivered electricity for end-use consumers. After the 2003 blackout that affected sections of the Northeastern and Midwestern United States and Ontario, Canada, the DOE established the Office of Electric Transmission and Distribution (now the Office of Electricity Delivery and Energy Reliability), focused on working with reliability experts from the power industry, state governments and their Canadian counterparts to improve grid reliability and increase investment in the country’s electric infrastructure. In addition, the FERC has signaled its desire for substantial new investment in the transmission sector by implementing various financial and other incentives.

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

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goals and has encouraged the legal and functional separation of transmission operations from generation and distribution operations.

The FERC requires compliance with certain reliability standards by TOs and may take enforcement actions for violations, including the imposition of substantial fines. NERC is responsible for developing and enforcing these mandatory reliability standards. We continually assess our transmission systems against standards established by NERC, as well as the standards of applicable regional entities under NERC that have been delegated certain authority for the purpose of proposing and enforcing reliability standards. Finally, utility holding companies are subject to FERC regulations related to access to books and records in addition to the requirement of the FERC to review and approve mergers and consolidations involving utility assets and holding companies in certain circumstances.

Federal Regulation

As electric transmission companies, our Regulated Operating Subsidiaries charge rates that are regulated by the FERC. The FERC is an independent regulatory commission within the DOE that regulates the interstate transmission and certain wholesale sales of natural gas, the transmission of oil and oil products by pipeline and the transmission and wholesale sales of electricity in interstate commerce. The FERC also administers accounting and financial reporting regulations and standards of conduct for the companies it regulates. In 1996, in order to facilitate open access transmission for participants in wholesale power markets, the FERC issued Order No. 888. The open access policy promulgated by the FERC in Order No. 888 was upheld in a United States Supreme Court decision, State of New York vs. FERC, issued on March 4, 2002. To facilitate open access, among other things, FERC Order No. 888 encouraged investor owned utilities to cede operational control over their transmission systems to ISOs, which are not-for-profit entities.

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

Order 1000 amends certain existing transmission planning and cost allocation requirements to ensure that FERC-jurisdictional services are provided at just and reasonable rates and on a basis that is just and reasonable and not unduly discriminatory or preferential. With respect to transmission planning, Order 1000: (1) requires that each public utility transmission provider participate in a regional transmission planning process that produces a regional transmission plan; (2) requires that each public utility transmission provider amend its Open Access Transmission Tariff to describe procedures that provide for the consideration of transmission needs driven by public policy requirements in the local and regional transmission planning processes; (3) removes a federal right of first refusal for certain new transmission facilities from FERC-approved tariffs and agreements; and (4) improves coordination between neighboring transmission planning regions for new interregional transmission facilities. MISO and SPP are compliant with the regional and interregional requirements of Order 1000 after making multiple compliance filings at the FERC.

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

Revenue Requirement Calculations and Cost Sharing for Projects with Regional Benefits

The cost-based formula rates used by our Regulated Operating Subsidiaries include revenue requirement calculations for various types of projects. Network revenues continue to be the largest component of revenues recovered through our formula rates. However, regional cost sharing revenues are growing as a result of projects that have been identified by MISO or SPP as having regional benefits, and therefore eligible for regional cost

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recovery under their tariffs. Separate calculations of revenue requirement are performed for projects that have been approved for regional cost sharing.

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

State Regulation

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

ITCTransmission, METC and ITC Interconnection

Michigan

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

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

ITC Midwest

Iowa

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

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

Minnesota

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

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

Illinois

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

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

Missouri

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

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

Wisconsin

ITC Midwest is a “public utility” and independent transmission owner in Wisconsin. The Public Service Commission of Wisconsin in a May 2014 order granted ITC Midwest a certificate of authority to transact public utility business in the state. In a separate May 2014 order, the Public Service Commission of Wisconsin also recognized ITC Holdings Corp. as a public utility holding company under Wisconsin statutes.

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

ITC Great Plains

Kansas

ITC Great Plains is a “public utility” in Kansas and an “electric utility” pursuant to state statutes. The Kansas Corporation Commission issued an order approving the issuance of a limited certificate of convenience to ITC Great Plains for the purposes of building, owning and operating SPP transmission projects in Kansas. In addition to its certificate of authority, the Kansas Corporation Commission has jurisdiction over the siting of electric transmission lines.

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

Oklahoma

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

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

Sources of Revenue

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

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Seasonality

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

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

Principal Customers

Our principal transmission service customers are DTE Electric, Consumers Energy and IP&L, which accounted for approximately 22.1%, 21.3% and 25.7%, respectively, of our consolidated billed revenues for the year ended December 31, 2017. One or more of these customers together have consistently represented a significant percentage of our operating revenue. These percentages of total billed revenues of DTE Electric, Consumers Energy and IP&L include the collection of 2015 revenue accruals and deferrals and exclude any amounts for the 2017 revenue accruals and deferrals that were included in our 2017 operating revenues, but will not be billed to our customers until 2019. Refer to “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cost-Based Formula Rates with True-Up Mechanism” for a discussion on the difference between billed revenues and operating revenues. Our remaining revenues were generated from providing service to other entities such as alternative electricity suppliers, power marketers and other wholesale customers that provide electricity to end-use consumers and from transaction-based capacity reservations. Nearly all of our revenues are from transmission customers in the United States. Although we may recognize allocated revenues from time to time from Canadian entities reserving transmission over the Ontario or Manitoba interface, these revenues have not been and are not expected to be material to us.

Billing

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

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

Competition

Each of our MISO Regulated Operating Subsidiaries operates the primary transmission system in its respective service area and has limited competition for certain projects. However, the competitive environment is evolving due to the implementation of Order 1000. See further discussion of Order 1000 above under “Regulatory Environment — Federal Regulation.” For our subsidiaries focused on development opportunities for transmission investment in other service areas, the incumbent utilities or other entities with transmission development initiatives may compete with us by seeking approval to be named the party authorized to build new capital projects that we are also pursuing.

Employees

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

Environmental Matters

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as claims for personal injury or property damage, may arise at many locations, including formerly owned or operated properties and sites where wastes have been treated or disposed of, as well as properties currently owned or operated by us. Such liabilities may arise even where the contamination does not result from noncompliance with applicable environmental laws. Under some environmental laws, such liabilities may also be joint and several, meaning that a party can be held responsible for more than its share of the liability involved, or even the entire share. Although environmental requirements generally have become more stringent and compliance with those requirements more expensive, we are not aware of any specific developments that would increase our costs for such compliance in a manner that would be expected to have a material adverse effect on our results of operations, financial position or liquidity.

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

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

Filings Under the Securities Exchange Act of 1934

Our internet address is http://www.itc-holdings.com. All of our reports filed pursuant to Section 13(a) or 15(d) of the Exchange Act, including our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports, can be accessed free of charge through our website. These reports are available as soon as practicable after they are electronically filed with the SEC. Our website also has posted our Code of Conduct and Ethics.

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

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

ITEM 1A. RISK FACTORS.

Risks Related to Our Business

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

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

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

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

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

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

We are subject to taxation by various taxing authorities at the federal, state and local levels. In December 2017, the President of the United States signed into law the TCJA, which enacted significant changes to the Internal Revenue Code including a reduction in the U.S. federal corporate income tax rate from 35% to 21% effective for tax years beginning after 2017. In addition, the TCJA provides modifications to bonus depreciation rules and limitations on the deductibility of interest expense, both of which include carve-outs for regulated utilities.

While certain aspects of the TCJA may be beneficial to ITC, overall we expect the enactment of the TCJA to adversely affect our results of operations, net income, financial condition and cash flows.

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

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

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

As a result of the changes made to Code Section 162(m) by the TCJA, some of the compensation we provide to our executive officers may not be deductible in 2018 and going forward.

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

Our actual capital investment may be lower than planned, which would cause a lower than anticipated rate base and would therefore result in lower revenues, earnings and associated cash flows compared to our current expectations. In addition, we expect to incur expenses related to the pursuit of development opportunities, which may be higher than forecasted.

Each of our operating subsidiaries’ rate base, revenues, earnings and associated cash flows are determined in part by additions to property, plant and equipment and when those additions are placed in service. We anticipate making significant capital investments over the next several years; however, the amounts could change significantly due to factors beyond our control. If our operating subsidiaries’ capital investment and the resulting in-service property, plant and equipment are lower than anticipated for any reason, our operating subsidiaries will have a lower than anticipated rate base, thus causing their revenue requirements and future earnings and cash flows to be lower than anticipated.

Any capital investment at our operating subsidiaries may be lower than our published estimates due to, among other factors, the impact of actual loads, forecasted loads, regional economic conditions, weather conditions, union strikes, labor shortages, material and equipment prices and availability, our ability to obtain financing for such expenditures, if necessary, limitations on the amount of construction that can be undertaken on our system or transmission systems owned by others at any one time, regulatory requirements relating to our rate construct, environmental issues, siting, regional planning, cost recovery or other issues, or as a result of legal proceedings and variances between estimated and actual costs of construction contracts awarded and the potential for greater competition. Our ability to engage in construction projects resulting from pursuing these initiatives is subject to significant uncertainties, including the factors discussed above, and will depend on obtaining any necessary regulatory and other approvals for the project and for us to initiate construction, our achieving status as the builder of the project in some circumstances and other factors. In addition, projects may be canceled, the scope of planned projects may change, or projects may not be completed on time, any of which may adversely affect our level of investment or cause our projected investments to be inaccurate. Therefore, we can provide no assurance as to the actual level of investment we may achieve at our operating subsidiaries.

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

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

Each of our Regulated Operating Subsidiaries is a “public utility” under the FPA and, accordingly, is subject to regulation by the FERC. Approval of the FERC is required under Section 203 of the FPA for a disposition or acquisition of regulated public utility facilities, either directly or indirectly through a holding company. Such approval is also required to acquire a significant interest in securities of a public utility. Section 203 of the FPA also provides

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the FERC with explicit authority over utility holding companies’ purchases or acquisitions of, and mergers or consolidations with, a public utility. Finally, each of our Regulated Operating Subsidiaries must also seek approval by the FERC under Section 204 of the FPA for issuances of its securities (including debt securities).

We are also pursuing development projects for construction of transmission facilities and interconnections with generating resources. These projects may require regulatory approval by Federal agencies, including the FERC, applicable RTOs and state and local regulatory agencies. Failure to secure such regulatory approval for new strategic development projects could adversely affect our ability to grow our business and increase our revenues. If we fail to obtain these approvals when necessary, we may incur liabilities for such failure.

Changes in energy laws, regulations or policies could impact our business, financial condition, results of operations and cash flows.

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

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

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

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

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

METC does not own the majority of the land on which its electric transmission assets are located. Instead, under the provisions of the Easement Agreement, METC pays an annual rent to Consumers Energy in exchange for rights-of-way, leases, fee interests and licenses which allow METC to use the land on which its transmission lines are located. Under the terms of the Easement Agreement, METC’s easement rights could be eliminated if METC fails to meet certain requirements, such as paying contractual rent to Consumers Energy in a timely manner. Additionally, a significant amount of the land on which our other subsidiaries’ assets are located is subject to easements, mineral rights and other similar encumbrances. As a result, they must comply with the provisions of various easements, mineral rights and other similar encumbrances, which may adversely impact their ability to complete their construction projects in a timely manner.

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

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

Hazards associated with high-voltage electricity transmission may result in suspension of our operations, costly litigation or the imposition of civil or criminal penalties.

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

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

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

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

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

If amounts billed for transmission service are lower than expected, which could result from lower network load or point-to-point transmission service on our Regulated Operating Subsidiaries’ transmission systems due to a weak economy, changes in the nature or composition of the transmission assets of our Regulated Operating Subsidiaries and surrounding areas, poor transmission quality of neighboring transmission systems, or for any other reason, the timing of actual collection of our total revenue requirement would likely be delayed until such circumstances are adjusted through the true-up mechanism in our Regulated Operating Subsidiaries’ formula rates. In addition, if the revenue requirements of our Regulated Operating Subsidiaries are higher than expected, due to higher actual expenditures compared to the forecasted expenditures used to develop their billing rates or for

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

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

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

Certain of our subsidiaries are also subject to requirements under Sections 203 and 205 of the FPA for approval of transactions; reporting, recordkeeping and accounting requirements; and for filing contracts related to the provision of jurisdictional services. Under FERC policy, failure to file jurisdictional agreements on a timely basis may result in foregoing the time value of revenues collected under the agreement, but not to the point where a loss would be incurred. The failure to obtain timely approval of transactions subject to FPA Section 203, or to comply with applicable reporting, recordkeeping or accounting requirements under FPA Section 205, could subject us to penalties that could have a material adverse effect on our financial condition, results of operations and cash flows.

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

Acts of war, terrorist attacks, cyber attacks, natural disasters, severe weather and other catastrophic events may negatively affect our business, financial condition and cash flows in unpredictable ways, such as increased security measures and disruptions of markets. Energy related assets, including, for example, our transmission facilities and DTE Electric’s, Consumers Energy’s and IP&L’s generation and distribution facilities that we interconnect with, may be at risk of acts of war, terrorist attacks and cyber attacks, as well as natural disasters, severe weather and other catastrophic events. In addition to any physical damage caused by such events, cyber attacks targeting our information systems could impair our records, networks, systems and programs, or transmit viruses to other systems. Such events or the threat of such events may increase costs associated with heightened security requirements. In addition, such events or threats may have a material effect on the economy in general and could result in a decline in energy consumption, which may have a material adverse effect on our business, financial condition, results of operations and cash flows.

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Risks Relating to Our Corporate and Financial Structure

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

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

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

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


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


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


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


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

•

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


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

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

Adverse changes in our credit ratings may negatively affect us.

Our ability to access capital markets is important to our ability to operate our business. Increased scrutiny of the energy industry and the impact of the TCJA and other statutory or regulatory changes, as well as changes in our financial performance and unfavorable conditions in the capital markets could result in credit agencies

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reexamining and downgrading our credit ratings. In addition, because we are now a subsidiary of Fortis, a downgrade in Fortis’ credit rating could cause our credit rating to be downgraded as well, even if our creditworthiness has not otherwise deteriorated. A downgrade in our credit ratings could restrict or discontinue our ability to access capital markets at attractive rates and increase our borrowing costs. A rating downgrade could also increase the interest we pay on commercial paper and under our revolving and term loan credit agreements.

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

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


•	incur additional indebtedness;


•	engage in sale and lease-back transactions;


•	create liens or other encumbrances;


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


•	create and acquire subsidiaries; and


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

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

ITEM 1B. UNRESOLVED STAFF COMMENTS.

None.

ITEM 2. PROPERTIES.

Our Regulated Operating Subsidiaries’ transmission facilities are located in Michigan and portions of Iowa, Minnesota, Illinois, Missouri, Kansas and Oklahoma. Our MISO Regulated Operating Subsidiaries and ITC Great Plains have agreements with other utilities for the joint ownership of specific substations, transmission lines and other transmission assets. See Note 15 to the consolidated financial statements for more information on the jointly owned assets.

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


•	approximately 3,100 circuit miles of overhead and underground transmission lines rated at voltages of 120 kV to 345 kV;


•	approximately 18,700 transmission towers and poles;


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


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


•	warehouses and related equipment;


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


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

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

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

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


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


•	approximately 37,500 transmission towers and poles;


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


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


•	warehouses and related equipment.

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

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

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


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


•	transmission towers and poles;


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


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


•	warehouses and related equipment; and


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

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

ITC Great Plains owns transmission and related assets including:


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


•	approximately 2,120 transmission towers and poles;


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


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


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

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

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ITC Interconnection owns certain substation assets and less than a mile of a transmission line rated at a voltage of 345 kV in Michigan. As of December 31, 2017, there were no liens or encumbrances on the assets of ITC Interconnection.

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

ITEM 3. LEGAL PROCEEDINGS.

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

Refer to Notes 5 and 17 to the consolidated financial statements for a description of certain pending legal proceedings, which description is incorporated herein by reference.

ITEM 4. MINE SAFETY DISCLOSURES.

Not applicable.

PART II



ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

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



Year Ended December 31, 2016	High		Low		Dividends
October 1 through October 14, 2016	$	46.48	$	44.91	$	—
Quarter ended September 30, 2016	47.46		44.64		0.2155
Quarter ended June 30, 2016	46.89		42.44		0.1875
Quarter ended March 31, 2016	43.89		36.53		0.1875

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

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ITEM 6. SELECTED FINANCIAL DATA.

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



	ITC Holdings and Subsidiaries
	Year Ended December 31,
(In millions)	2017			2016			2015			2014			2013
OPERATING REVENUES (a)	$	1,211		$	1,125		$	1,045		$	1,023		$	941
OPERATING EXPENSES
Operation and maintenance	110			114			113			112			113
General and administrative (b) (c) (d)	123			239			145			115			149
Depreciation and amortization	169			158			145			128			119
Taxes other than income taxes	103			93			82			76			66
Other operating income and expense — net	(2		)	(1		)	(1		)	(1		)	(2		)
Total operating expenses	503			603			484			430			445
OPERATING INCOME	708			522			561			593			496
OTHER EXPENSES (INCOME)
Interest expense — net (e)	224			211			204			216			168
Allowance for equity funds used during construction	(33		)	(35		)	(28		)	(21		)	(30		)
Other income	(3		)	(2		)	(2		)	(1		)	(1		)
Other expense	5			5			3			5			7
Total other expenses (income)	193			179			177			199			144
INCOME BEFORE INCOME TAXES	515			343			384			394			352
INCOME TAX PROVISION	196			97			142			150			119
NET INCOME	$	319		$	246		$	242		$	244		$	233



	ITC Holdings and Subsidiaries
	As of December 31,
(In millions)	2017			2016			2015			2014			2013
BALANCE SHEET DATA:
Cash and cash equivalents	$	66		$	8		$	14		$	28		$	34
Working capital (deficit) (f)	(302		)	(400		)	(550		)	(291		)	(325		)
Property, plant and equipment — net	7,309			6,698			6,110			5,497			4,847
Goodwill	950			950			950			950			950
Total assets (f) (g)	8,823			8,223			7,555			6,932			6,241
Debt:
ITC Holdings (g)	2,728			2,387			2,304			2,123			1,871
Regulated Operating Subsidiaries (g)	2,373			2,203			2,125			1,954			1,717
Total debt (g)	5,101			4,590			4,429			4,077			3,588
Total stockholder’s equity	$	1,920		$	1,901		$	1,709		$	1,670		$	1,614



	ITC Holdings and Subsidiaries
	Year Ended December 31,
(In millions)	2017		2016		2015		2014		2013
CASH FLOWS DATA:
Expenditures for property, plant and equipment	$	755	$	750	$	701	$	753	$	824

____________________________


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

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

(b)

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

(c)

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

(d)

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


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


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


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



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

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

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

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

Overview

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

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generating stations to local distribution facilities connected to our systems. Our business strategy is to own, operate, maintain and invest in transmission infrastructure in order to enhance system integrity and reliability, reduce transmission constraints and support new generating resources to interconnect to our transmission systems. We also are pursuing development projects not within our existing systems, which are also intended to improve overall grid reliability, reduce transmission constraints and facilitate interconnections of new generating resources, as well as enhance competitive wholesale electricity markets.

As electric transmission utilities whose rates are regulated by the FERC, our Regulated Operating Subsidiaries earn revenues for the use of their electric transmission systems by our customers. We derive nearly all of our revenues from providing electric transmission service over our Regulated Operating Subsidiaries’ transmission systems to investor-owned utilities, such as DTE Electric, Consumers Energy and IP&L, and other entities, such as alternative electricity suppliers, power marketers and other wholesale customers that provide electricity to end-use consumers as well as from transaction-based capacity reservations on our transmission systems.

As independent transmission companies, our Regulated Operating Subsidiaries are subject to rate regulation only by the FERC, and our cost-based rates are discussed below in “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cost-Based Formula Rates with True-Up Mechanism” as well as in Note 5 to the consolidated financial statements.

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

Significant recent matters that influenced our financial position and results of operations and cash flows for the year ended December 31, 2017 or that may affect future results include:


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


•	Our capital expenditures of $755 million at our Regulated Operating Subsidiaries during the year ended December 31, 2017, as described below under “— Capital Investment and Operating Results Trends,” resulting primarily from our focus on improving system reliability, increasing system capacity and upgrading the transmission network to support new generating resources;


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


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

•

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

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

Cost-Based Formula Rates with True-Up Mechanism

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

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

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

See “Cost-Based Formula Rates with True-Up Mechanism” in Note 5 for further discussion of our formula rates and see “Rate of Return on Equity Complaints” in Note 17 to the consolidated financial statements for detail on ROE matters.

Illustrative Example of Formula Rate Setting

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



Line	Item	Instructions	Amount
1	Rate base (a)		$	1,000,000
2	Multiply by 13-month weighted average cost of capital (b)		8.81		%
3	Allowed return on rate base	(Line 1 x Line 2)	$	88,100
4	Recoverable operating expenses (including depreciation and amortization)		$	150,000
5	Income taxes (c)		50,000
6	Gross revenue requirement	(Line 3 + Line 4 + Line 5)	$	288,100

____________________________


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

(b)

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



			Weighted
			Average
	Percentage of		Cost of
	Total Capitalization	Cost of Capital	Capital
Debt	40.00%	5.00% =	2.00	%
Equity	60.00%	11.35% =	6.81	%
	100.00%		8.81	%


(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.

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Revenue Accruals and Deferrals — Effects of Monthly Peak Loads

For our MISO Regulated Operating Subsidiaries, monthly peak loads are used for billing network revenues, which currently is the largest component of our operating revenues. One of the primary factors that impacts the revenue accruals and deferrals at our MISO Regulated Operating Subsidiaries is actual monthly peak loads experienced as compared to those forecasted in establishing the annual network transmission rate. Under their cost-based formula rates that contain a true-up mechanism, our MISO Regulated Operating Subsidiaries accrue or defer revenues to the extent that their actual revenue requirement for the reporting period is higher or lower, respectively, than the amounts billed relating to that reporting period. Although monthly peak loads do not impact operating revenues recognized, network load affects the timing of our cash flows from transmission service. The monthly peak load of our MISO Regulated Operating Subsidiaries is generally impacted by weather and economic conditions and seasonally shaped with higher load in the summer months when cooling demand is higher.

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

Capital Investment and Operating Results Trends

We expect a long-term upward trend in revenues and earnings, subject to the impact of:


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


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


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

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

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

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We also assess our transmission systems against our own planning criteria that are filed annually with the FERC. Based on our planning studies, we see needs to make capital investments to: (1) rebuild existing property, plant and equipment; (2) upgrade the system to address demographic changes that have impacted transmission load and the changing role that transmission plays in meeting the needs of the wholesale market, including accommodating the siting of new generation or increasing import capacity to meet changes in peak electrical demand; (3) relieve congestion in the transmission systems; and (4) achieve state and federal policy goals, such as renewable generation portfolio standards. The following table shows our actual and expected capital expenditures at our Regulated Operating Subsidiaries:



	Actual Capital		Forecasted
	Expenditures for the		Capital
	year ended		Expenditures
(In millions)	December 31, 2017		2018 — 2022
Expenditures for property, plant and equipment (a)	$	755	$	2,842

____________________________


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

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

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

Recent Developments

2017 Tax Reform

In December 2017, the President of the United States of America signed into law the TCJA, which enacted significant changes to the Internal Revenue Code including a reduction in the U.S. federal corporate income tax rate from 35% to 21% effective for tax years beginning after 2017. We were required to revalue our deferred tax assets and liabilities at the new federal corporate income tax rate as of the date of enactment of the TCJA. The majority of our deferred tax assets and liabilities as well as a portion of its U.S. federal net operating losses are held at our Regulated Operating Subsidiaries. The majority of the deferred tax assets and liabilities at the Regulated Operating Subsidiaries are subject to a normalization method of accounting pursuant to the Internal Revenue Code. As a result, the revaluation of the Regulated Operating Subsidiaries net deferred taxes resulted in a net regulatory liability of approximately $512 million at December 31, 2017 and a reduction in regulatory assets of $65 million that would be returned to or received from customers over a period of time. The revaluation of the deferred tax assets and federal income tax net operating losses at ITC Holdings has resulted in additional income tax expense in the fourth quarter of 2017 of $5 million. For additional information on the impacts of tax reform, see Note 6 and Note 10 to the consolidated financial statements.

The Merger

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

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

Rate of Return on Equity Complaints

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

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

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



	Year Ended December 31,
(In millions)	2017		2016		2015
Revenue reduction	$	—	$	80	$	115
Interest expense increase	6		10		5
Estimated net income reduction (a)	3		55		73

____________________________


(a)	Includes an effect on net income of $27 million and $28 million for the year ended December 31, 2016 and 2015, respectively, for revenue initially recognized in 2015, 2014 and 2013.

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

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Significant Components of Results of Operations

Revenues

We derive nearly all of our revenues from providing transmission, scheduling, control and dispatch services and other related services over our Regulated Operating Subsidiaries’ transmission systems to DTE Electric, Consumers Energy, IP&L and other entities, such as alternative electricity suppliers, power marketers and other wholesale customers that provide electricity to end-use consumers, as well as from transaction-based capacity reservations on our transmission systems. MISO and SPP are responsible for billing and collecting the majority of transmission service revenues. As the billing agent for our MISO Regulated Operating Subsidiaries and ITC Great Plains, MISO and SPP collect fees for the use of our transmission systems, invoicing DTE Electric, Consumers Energy, IP&L and other customers on a monthly basis.

Network Revenues are generated from network customers for their use of our electric transmission systems and are based on the actual revenue requirements as a result of our accounting under our cost-based formula rates that contain a true-up mechanism. Refer to “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates — Revenue Recognition under Cost-Based Formula Rates with True-Up Mechanism” for a discussion of revenue recognition relating to network revenues.

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

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

Regional Cost Sharing Revenues are generated from transmission customers throughout RTO regions for their use of our MISO Regulated Operating Subsidiaries’ network upgrade projects that are eligible for regional cost sharing under provisions of the MISO tariff, including MVP projects such as our portion of four MVPs and the Thumb Loop Project in Michigan. Regional cost sharing revenue also includes revenues collected by transmission customers from other RTOs outside of MISO to allocate costs of certain transmission plant investments. Additionally, certain projects at ITC Great Plains are eligible for recovery through a region-wide charge under provisions of the SPP tariff. A portion of regional cost sharing revenues is treated as a revenue credit to regional or network customers and is a reduction to gross revenue requirement when calculating net revenue requirement under our cost-based formula rates.

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

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

Operating Expenses

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

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

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

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

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

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

Other Items of Income or Expense

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

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

Income Tax Provision

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

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Results of Operations

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



	Year Ended									Percentage	Year Ended						Percentage
	December 31,						Increase			Increase	December 31,			Increase			Increase
(In millions)	2017			2016			(Decrease)			(Decrease)	2015			(Decrease)			(Decrease)
OPERATING REVENUES	$	1,211		$	1,125		$	86		8%	$	1,045		$	80		8%
OPERATING EXPENSES
Operation and maintenance	110			114			(4		)	(4)%	113			1			1%
General and administrative	123			239			(116		)	(49)%	145			94			65%
Depreciation and amortization	169			158			11			7%	145			13			9%
Taxes other than income taxes	103			93			10			11%	82			11			13%
Other operating income and expenses — net	(2		)	(1		)	(1		)	100%	(1		)	—			—%
Total operating expenses	503			603			(100		)	(17)%	484			119			25%
OPERATING INCOME	708			522			186			36%	561			(39		)	(7)%
OTHER EXPENSES (INCOME)
Interest expense — net	224			211			13			6%	204			7			3%
Allowance for equity funds used during construction	(33		)	(35		)	2			(6)%	(28		)	(7		)	25%
Other income	(3		)	(2		)	(1		)	50%	(2		)	—			—%
Other expense	5			5			—			—%	3			2			67%
Total other expenses (income)	193			179			14			8%	177			2			1%
INCOME BEFORE INCOME TAXES	515			343			172			50%	384			(41		)	(11)%
INCOME TAX PROVISION	196			97			99			102%	142			(45		)	(32)%
NET INCOME	$	319		$	246		$	73		30%	$	242		$	4		2%

Operating Revenues

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	$	816		67	%	$	814		72	%	$	2		—	%
Regional cost sharing revenues	340			28	%	337			30	%	3			1	%
Point-to-point	18			2	%	20			2	%	(2		)	(10	)%
Scheduling, control and dispatch	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	%

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

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

Operating revenues for the years ended December 31, 2017 and 2016 include revenue accruals and deferrals as described in Note 5 to the consolidated financial statements.

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

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



													Percentage
	2016					2015					Increase		Increase
(In millions)	Amount			Percentage		Amount			Percentage		(Decrease)		(Decrease)
Network revenues	$	814		72	%	$	802		77	%	$	12	1	%
Regional cost sharing revenues	337			30	%	328			31	%	9		3	%
Point-to-point	20			2	%	15			2	%	5		33	%
Scheduling, control and dispatch	14			1	%	13			1	%	1		8	%
Other	20			2	%	12			1	%	8		67	%
Recognition of refund liabilities	(80		)	(7	)%	(125		)	(12	)%	45		(36	)%
Total	$	1,125		100	%	$	1,045		100	%	$	80	8	%

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

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

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

Operating revenues for the years ended December 31, 2016 and 2015 include revenue accruals and deferrals as described in Note 5 to the consolidated financial statements.

Operating Expenses

Operation and maintenance expenses

Year ended December 31, 2017 compared to the respective period in 2016 and the year ended December 31, 2016 compared to the respective period in 2015

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

General and administrative expenses

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

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

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

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

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

Depreciation and amortization expenses

Year ended December 31, 2017 compared to the respective period in 2016 and the year ended December 31, 2016 compared to the respective period in 2015

Depreciation and amortization expenses increased in the respective period due primarily to a higher depreciable base resulting from property, plant and equipment in-service additions.

Taxes other than income taxes

Year ended December 31, 2017 compared to the respective period in 2016 and the year ended December 31, 2016 compared to the respective period in 2015

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

Other expenses (income)

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

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

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

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

AFUDC equity increased due primarily to higher balances of construction work in progress eligible for AFUDC equity during the period.

Income Tax Provision

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

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

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

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

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Liquidity and Capital Resources

We expect to maintain our approach of funding our future capital requirements with cash from operations at our Regulated Operating Subsidiaries, our existing cash and cash equivalents, future issuances under our commercial paper program and amounts available under our revolving and term loan credit agreements (the terms of which are described in Note 9 to the consolidated financial statements). In addition, we may from time to time secure debt funding in the capital markets, although we can provide no assurance that we will be able to obtain financing on favorable terms or at all. As market conditions warrant, we may also from time to time repurchase debt securities issued by us, in the open market, in privately negotiated transactions, by tender offer or otherwise. We expect that our capital requirements will arise principally from our need to:


•	Fund capital expenditures at our Regulated Operating Subsidiaries. Our plans with regard to property, plant and equipment investments are described in detail above under “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Investment and Operating Results Trends.”

•

Fund business development expenses and related capital expenditures. We are pursuing development activities for projects that will continue to result in the incurrence of development expenses and could result in significant capital expenditures incremental to our current plan. Refer to Note 17 to the consolidated financial statements for a discussion of contingent payments related to development projects.


•	Fund working capital requirements.

•

Fund our debt service requirements, including principal repayments and periodic interest payments, which are further described in detail below under “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Contractual Obligations.” We expect our interest payments to increase each year as a result of additional debt expected to be incurred to fund our capital expenditures and for general corporate purposes.


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


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


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


•	Fund contributions to our retirement benefit plans, as described in Note 11 to the consolidated financial statements. We expect to contribute up to $14 million to these plans in 2018.

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

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

We expect to continue to utilize our commercial paper program and revolving and term loan credit agreements as well as our cash and cash equivalents as needed to meet our short-term cash requirements. As of December 31, 2017, we had consolidated indebtedness under our revolving and term loan credit agreements of $271 million, with unused capacity under the revolving credit agreements of $679 million. Additionally, ITC Holdings had no commercial paper issued and outstanding as of December 31, 2017, with the ability to issue $400 million under the commercial paper program. See Note 9 to the consolidated financial statements for a detailed discussion of the commercial paper program and our revolving and term loan credit agreements as well as the debt activity during the years ended December 31, 2017 and 2016.

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As of December 31, 2017, we had approximately $100 million of fixed rate debt maturing within one year, which we expect to repay with borrowings under our revolving credit agreements or refinance with long-term debt. To address our long-term capital requirements, we expect that we will need to obtain additional debt financing. Certain of our capital projects could be delayed if we experience difficulties in accessing capital. We expect to be able to obtain such additional financing as needed, in amounts and upon terms that will be reasonably satisfactory to us due to our strong credit ratings and our historical ability to obtain financing.

Credit Ratings

Credit ratings by nationally recognized statistical rating agencies are an important component of our liquidity profile. Credit ratings relate to our ability to issue debt securities and the cost to borrow money, and should not be viewed as recommendation to buy, sell or hold securities. Ratings are subject to revision or withdrawal at any time and each rating should be evaluated independently of any other rating. Our current credit ratings are displayed in the following table. An explanation of these ratings may be obtained from the respective rating agency.



		Standard and Poor’s	Moody’s Investor
Issuer	Issuance	Ratings Services (a)	Service, Inc. (b)
ITC Holdings	Senior Unsecured Notes	A-	Baa2
ITC Holdings	Commercial Paper	A-2	Prime-2
ITCTransmission	First Mortgage Bonds	A	A1
METC	Senior Secured Notes	A	A1
ITC Midwest	First Mortgage Bonds	A	A1
ITC Great Plains	First Mortgage Bonds	A	A1

____________________________

(a)

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

(b)

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

Covenants

Our debt instruments contain numerous financial and operating covenants that place significant restrictions on certain transactions as well as require us to meet certain financial ratios, which are described in Note 9 to the consolidated financial statements. As of December 31, 2017, we were not in violation of any debt covenant. In the event of a downgrade in our credit ratings, none of the covenants would be directly impacted, although the borrowing costs under our revolving credit agreements may increase.

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Cash Flows

The following table summarizes cash flows for the periods indicated:



	Year Ended December 31,
(In millions)	2017			2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	319		$	246		$	242
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	169			158			145
Recognition, refund and collection of revenue accruals and deferrals — including accrued interest	34			(2		)	(54		)
Deferred income tax expense	195			219			77
Other	(109		)	66			146
Net cash provided by operating activities	608			687			556
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(755		)	(750		)	(701		)
Other	11			15			1
Net cash used in investing activities	(744		)	(735		)	(700		)
CASH FLOWS FROM FINANCING ACTIVITIES
Net issuance/repayment of debt (including commercial paper and revolving and term loan credit agreements)	511			161			352
Issuance of common stock	—			13			14
Dividends on common and restricted stock	—			(90		)	(108		)
Dividends to ITC Investment Holdings Inc.	(300		)	(33		)	—
Refundable deposits from and repayments to generators for transmission network upgrades — net	(12		)	23			1
Repurchase and retirement of common stock	—			(9		)	(137		)
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		)	(23		)	8
Net cash provided by financing activities	194			42			130
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	58			(6		)	(14		)
CASH AND CASH EQUIVALENTS — Beginning of period	8			14			28
CASH AND CASH EQUIVALENTS — End of period	$	66		$	8		$	14

Cash Flows From Operating Activities

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

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

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

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

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

Cash Flows From Investing Activities

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

Net cash used in investing activities during the year ended December 31, 2017 was comparable to the same period in 2016.

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

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

Cash Flows From Financing Activities

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

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

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

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

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Contractual Obligations

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



			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	$	500	$	2,050
ITCTransmission First Mortgage Bonds	585		100		—		—		485
ITCTransmission revolving credit agreement	36		—		—		36		—
ITCTransmission term loan credit agreement	50		—		50		—		—
METC Senior Secured Notes	475		—		—		—		475
METC revolving credit agreement	48		—		—		48		—
ITC Midwest First Mortgage Bonds	910		—		35		—		875
ITC Midwest revolving credit agreement	88		—		—		88		—
ITC Great Plains First Mortgage Bonds	150		—		—		—		150
ITC Great Plains revolving credit agreement	49		—		—		49		—
Interest payments:
ITC Holdings Senior Notes	1,159		108		205		192		654
ITCTransmission First Mortgage Bonds	564		25		47		47		445
METC Senior Secured Notes	528		20		40		40		428
ITC Midwest First Mortgage Bonds	948		41		83		77		747
ITC Great Plains First Mortgage Bonds	167		6		12		12		137
Operating leases	4		1		1		1		1
Purchase obligations	72		71		1		—		—
Regulatory liabilities — revenue deferrals, including accrued interest	64		38		26		—		—
METC Easement Agreement	329		10		20		20		279
Other	1		1		—		—		—
Total obligations	$	8,977	$	421	$	720	$	1,110	$	6,726

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

Operating leases include leases for office space, equipment and storage facilities. Purchase obligations represent commitments primarily for materials, services and equipment that had not been received as of December 31, 2017, primarily for construction and maintenance projects for which we have an executed contract. The majority of the items relate to materials and equipment that have long production lead times. See Note 17 to the consolidated financial statement for more information on our operating leases and purchases obligations.

The revenue deferrals, including accrued interest, in the table above represent the over-recovery of revenues resulting from differences between the amounts billed to customers and actual revenue requirement at each of our Regulated Operating Subsidiaries, as described in Note 5 to the consolidated financial statements. These amounts will offset future revenue requirement for purposes of calculating our formula rates as part of the true-up mechanism in our rate construct.

The Easement Agreement provides METC with an easement for transmission purposes and rights-of-way, leasehold interests, fee interests and licenses associated with the land over which the transmission lines cross. The cost for use of the rights-of-way is $10 million per year. The term of the Easement Agreement runs through December 31, 2050 and is subject to 10 automatic 50-year renewals thereafter unless METC gives notice of

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nonrenewal of at least one year in advance. Payments to Consumers Energy under the Easement Agreement are charged to operation and maintenance expense.

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

Critical Accounting Policies and Estimates

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

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

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

Regulation

Our Regulated Operating Subsidiaries are subject to rate regulation by the FERC. As a result, we apply accounting principles in accordance with the standards set forth by the FASB for accounting for the effects of certain types of regulation. Use of this accounting guidance results in differences in the application of GAAP between regulated and non-regulated businesses and requires the recording of regulatory assets and liabilities for certain transactions that would have been treated as expense or revenue in non-regulated businesses. As described in Note 6 to the consolidated financial statements, we had regulatory assets and liabilities of $215 million and $802 million, respectively, as of December 31, 2017. Future changes in the regulatory and competitive environments could result in discontinuing the application of the accounting standards for the effects of certain types of regulations. If we were to discontinue the application of this guidance on the operations of our Regulated Operating Subsidiaries, we may be required to record losses relating to certain regulatory assets or gains relating to certain regulatory liabilities. We also may be required to record losses of $41 million relating to intangible assets at December 31, 2017 that are described in Note 7 to the consolidated financial statements.

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

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

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

Under their formula rates, our Regulated Operating Subsidiaries use forecasted expenses, property, plant and equipment, point-to-point revenues and other items for the upcoming calendar year to establish their projected revenue requirement and for the MISO Regulated Operating Subsidiaries, their component of the billed network rates for service on their systems from January 1 to December 31 of that year. The cost-based formula rates include a true-up mechanism, whereby our Regulated Operating Subsidiaries compare their actual revenue requirements to their billed revenues for each year in order to subsequently collect or refund any over-recovery or under-recovery of revenues, as appropriate. The over- or under-collection typically results from differences between the projected revenue requirement used as the basis for billing and actual revenue requirement at each of our Regulated Operating Subsidiaries, or from differences between actual and projected monthly peak loads at our MISO Regulated Operating Subsidiaries.

The true-up mechanism under our formula rates meet the GAAP requirements for accounting for rate-regulated utilities and the effects of certain alternative revenue programs. Accordingly, revenue is recognized during each

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reporting period based on actual revenue requirements calculated using the cost-based formula rates. Our Regulated Operating Subsidiaries accrue or defer revenues to the extent that their actual revenue requirement for the reporting period is higher or lower, respectively, than the amounts billed relating to that reporting period. The true-up amount is automatically reflected in customer bills within two years under the provisions of the formula rates. See Note 5 to the consolidated financial statements for the regulatory assets and liabilities recorded at our Regulated Operating Subsidiaries’ as a result of the formula rate revenue accruals and deferrals.

Valuation of Goodwill

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

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

As of December 31, 2017 and 2016, consolidated goodwill totaled $950 million. We completed our annual goodwill impairment test for our reporting units as of October 1, 2017 using a qualitative assessment and determined that no impairment exists. There were no events subsequent to October 1, 2017, including the enactment of the TCJA, that indicated impairment of our goodwill. We do not believe there is a material risk of our goodwill being impaired in the near term for any of our reporting units.

Contingent Obligations

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


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


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


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


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


•	Completion of certain milestones relating to development initiatives.

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Refer to Note 17 to the consolidated financial statements for discussion on contingencies, including the ROE complaints.

Pension and Postretirement Costs

We sponsor certain retirement benefits for our employees, which include retirement pension plans and certain postretirement health care, dental and life insurance benefits. Our periodic costs and obligations associated with these plans are developed from actuarial valuations derived from a number of assumptions, including rates of return on plan assets, the discount rates, the rate of increase in health care costs, the amount and timing of plan sponsor contributions and demographic factors such as retirements, mortality and turnover, among others. We evaluate these assumptions annually and update them periodically to reflect our actual experience. Three critical assumptions in determining our periodic costs and obligations are discount rate, expected long-term return on plan assets and the rate of increases in health care costs. The discount rate represents the market rate for synthesized AA-rated zero-coupon bonds with durations corresponding to the expected durations of the benefit obligations and is used to calculate the present value of the expected future cash flows for benefit obligations under our plans. In determining our long-term rate of return on plan assets, we consider the current and expected asset allocations, as well as historical and expected long-term rates of return on those types of asset classes. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans as described in Note 11 to the consolidated financial statements.

Off-Balance Sheet Arrangements

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

Recent Accounting Pronouncements

See Note 3 to the consolidated financial statements.

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

Commodity Price Risk

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

Interest Rate Risk

Fixed Rate Debt

Based on the borrowing rates obtained from third party lending institutions currently available for bank loans with similar terms and average maturities from active markets, the fair value of our consolidated long-term debt and debt maturing within one year, excluding revolving and term loan credit agreements and commercial paper, was $5,192 million at December 31, 2017. The total book value of our consolidated long-term debt and debt maturing within one year, net of discount and deferred financing fees and excluding revolving and term loan credit agreements and commercial paper, was $4,830 million at December 31, 2017. We performed an analysis calculating the impact of changes in interest rates on the fair value of long-term debt and debt maturing within one year, excluding revolving credit agreements and commercial paper, at December 31, 2017. An increase in interest rates of 10% (from 5.0% to 5.5%, for example) at December 31, 2017 would decrease the fair value of debt by $198 million, and a decrease in interest rates of 10% at December 31, 2017 would increase the fair value of debt by $212 million at that date.

Revolving and Term Loan Credit Agreements

At December 31, 2017, we had a consolidated total of $271 million outstanding under our revolving and term loan credit agreements, which are variable rate loans. The fair value of these loans approximates book value based on the borrowing rates currently available for variable rate loans obtained from third party lending institutions. A 10% increase or decrease in borrowing rates under the revolving and term loan credit agreements compared to the weighted average rates in effect at December 31, 2017 would increase or decrease interest expense by $1 million, respectively, for an annual period with a constant borrowing level of $271 million.

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Commercial Paper

ITC Holdings has an ongoing commercial paper program for the issuance and sale of unsecured commercial paper. At December 31, 2017, ITC Holdings did not have any commercial paper issued or outstanding.

Derivative Instruments and Hedging Activities

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

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

Credit Risk

Our credit risk is primarily with DTE Electric, Consumers Energy and IP&L, which were responsible for approximately 22.1%, 21.3% and 25.7%, respectively, or $280 million, $269 million and $325 million, respectively, of our consolidated billed revenues for the year ended December 31, 2017. These percentages and amounts of total billed revenues of DTE Electric, Consumers Energy and IP&L include the collection of 2015 revenue accruals and deferrals and exclude any amounts for the 2017 revenue accruals and deferrals that were included in our 2017 operating revenues, but will not be billed to our customers until 2019. Refer to “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cost-Based Formula Rates with True-Up Mechanism” for a discussion on the difference between billed revenues and operating revenues. Under DTE Electric’s and Consumers Energy’s current rate structure, DTE Electric and Consumers Energy include in their retail rates the actual cost of transmission services provided by ITCTransmission and METC, respectively, in their billings to their customers, effectively passing through to end-use consumers the total cost of transmission service. IP&L currently includes in their retail rates an allowance for transmission services provided by ITC Midwest in their billings to their customers. However, any financial difficulties experienced by DTE Electric, Consumers Energy or IP&L may affect their ability to make payments for transmission service to ITCTransmission, METC, and ITC Midwest, which could negatively impact our business. MISO, as our MISO Regulated Operating Subsidiaries’ billing agent, bills DTE Electric, Consumers Energy, IP&L and other customers on a monthly basis and collects fees for the use of the MISO Regulated Operating Subsidiaries’ transmission systems. SPP is the billing agent for ITC Great Plains and bills transmission customers for the use of ITC Great Plains transmission systems. MISO and SPP have implemented strict credit policies for its members’ customers, which include customers using our transmission systems. Specifically, MISO and SPP require a letter of credit or cash deposit equal to the credit exposure, which is determined by a credit scoring model and other factors, from any customer using a member’s transmission system.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

The following financial statements and schedules are included herein:



		Page
Management’s Report on Internal Control over Financial Reporting		47
Report of Independent Registered Public Accounting Firm		48
Consolidated Statements of Financial Position as of December 31, 2017 and 2016		49
Consolidated Statements of Operations for the Years Ended December 31, 2017, 2016 and 2015		50
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2017, 2016 and 2015		51
Consolidated Statements of Changes in Stockholder’s Equity for the Years Ended December 31, 2017, 2016 and 2015		52
Consolidated Statements of Cash Flows for the Years Ended December 31, 2017, 2016 and 2015		53
Notes to Consolidated Financial Statements		54
Schedule I — Condensed Financial Information of Registrant		135

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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is designed to provide reasonable, not absolute, assurance as to the reliability of our financial reporting and the preparation of financial statements in accordance with generally accepted accounting principles. Internal control over financial reporting, no matter how well designed, has inherent limitations. Therefore, internal control over financial reporting determined to be effective can provide only reasonable assurance with respect to financial statement preparation and may not prevent or detect all misstatements.

Under management’s supervision, an evaluation of the design and effectiveness of our internal control over financial reporting was conducted based on the criteria set forth in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Our assessment included extensive documenting, evaluating and testing of the design and operating effectiveness of our internal control over financial reporting. Based on this evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2017.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of

ITC Holdings Corp.:

Novi, Michigan

Opinion on the Financial Statements

We have audited the accompanying consolidated statements of financial position of ITC Holdings Corp. and subsidiaries (the "Company") as of December 31, 2017 and 2016, the related consolidated statements of operations, comprehensive income, changes in stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2017, and the related notes and the schedule listed in the Index at Item 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material aspects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

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

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

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

/s/ DELOITTE & TOUCHE LLP

Detroit, Michigan

February 14, 2018

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

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ITC HOLDINGS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION



	December 31,
(In millions, except share data)	2017		2016
ASSETS
Current assets
Cash and cash equivalents	$	66	$	8
Accounts receivable	119		108
Inventory	29		29
Regulatory assets	18		53
Income tax receivable	15		17
Prepaid and other current assets	13		18
Total current assets	260		233
Property, plant and equipment (net of accumulated depreciation and amortization of $1,675 and $1,575, respectively)	7,309		6,698
Other assets
Goodwill	950		950
Intangible assets (net of accumulated amortization of $35 and $32, respectively)	41		43
Regulatory assets	197		247
Other	66		52
Total other assets	1,254		1,292
TOTAL ASSETS	$	8,823	$	8,223
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities
Accounts payable	$	97	$	100
Accrued compensation	28		14
Accrued interest	60		54
Accrued taxes	57		49
Regulatory liabilities	183		129
Refundable deposits from generators for transmission network upgrades	3		17
Debt maturing within one year	100		235
Other	34		35
Total current liabilities	562		633
Accrued pension and postretirement liabilities	74		68
Deferred income taxes	601		964
Regulatory liabilities	619		249
Refundable deposits from generators for transmission network upgrades	29		27
Other	17		26
Long-term debt	5,001		4,355
Commitments and contingent liabilities (Notes 5 and 17)
STOCKHOLDER’S EQUITY
Common stock, without par value, 235,000,000 shares authorized as of December 31, 2017, and 224,203,112 shares issued and outstanding at December 31, 2017 and 2016.	892		892
Retained earnings	1,026		1,007
Accumulated other comprehensive income	2		2
Total stockholder’s equity	1,920		1,901
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	8,823	$	8,223

See notes to consolidated financial statements.

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ITC HOLDINGS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS



	Year Ended December 31,
(In millions)	2017			2016			2015
OPERATING REVENUES	$	1,211		$	1,125		$	1,045
OPERATING EXPENSES
Operation and maintenance	110			114			113
General and administrative	123			239			145
Depreciation and amortization	169			158			145
Taxes other than income taxes	103			93			82
Other operating income and expense — net	(2		)	(1		)	(1		)
Total operating expenses	503			603			484
OPERATING INCOME	708			522			561
OTHER EXPENSES (INCOME)
Interest expense — net	224			211			204
Allowance for equity funds used during construction	(33		)	(35		)	(28		)
Other income	(3		)	(2		)	(2		)
Other expense	5			5			3
Total other expenses (income)	193			179			177
INCOME BEFORE INCOME TAXES	515			343			384
INCOME TAX PROVISION	196			97			142
NET INCOME	$	319		$	246		$	242

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)	2017		2016			2015
NET INCOME	$	319	$	246		$	242
OTHER COMPREHENSIVE LOSS
Derivative instruments, net of tax (Note 13)	—		(2		)	(1		)
TOTAL OTHER COMPREHENSIVE LOSS, NET OF TAX (NOTE 13)	—		(2		)	(1		)
TOTAL COMPREHENSIVE INCOME	$	319	$	244		$	241

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, 2014	$	924		$	741		$	5		$	1,670
Net income	—			242			—			242
Repurchase and retirement of common stock	(137		)	—			—			(137		)
Dividends declared on common stock	—			(108		)	—			(108		)
Stock option exercises	11			—			—			11
Share-based compensation, net of forfeitures	18			—			—			18
Tax benefit for excess tax deductions of share-based compensation	12			—			—			12
Other comprehensive loss, net of tax (Note 13)	—			—			(1		)	(1		)
Other	1			1			—			2
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 14)	41			—			—			41
Settlement of share-based awards associated with the Merger (Note 16)	(137		)	(1		)	—			(138		)
Contribution from ITC Investment Holdings Inc. for the settlement of share-based awards associated with the Merger (Note 16)	137			—			—			137
Tax benefit for excess tax deductions of share-based compensation	—			9			—			9
Other comprehensive loss, net of tax (Note 13)	—			—			(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

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)	2017			2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	319		$	246		$	242
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	169			158			145
Recognition, refund and collection of revenue accruals and deferrals — including accrued interest	34			(2		)	(54		)
Deferred income tax expense	195			219			77
Allowance for equity funds used during construction	(33		)	(35		)	(28		)
Expense for the accelerated vesting of share-based awards associated with the Merger	—			41			—
Other	11			30			22
Changes in assets and liabilities, exclusive of changes shown separately:
Accounts receivable	(17		)	(2		)	(1		)
Current regulatory assets	29			(29		)	—
Income tax receivable	—			(17		)	—
Other current assets	—			(4		)	2
Accounts payable	(3		)	5			(7		)
Accrued compensation	14			(11		)	—
Accrued taxes	5			4			15
Other current liabilities	2			3			9
Estimated refund related to return on equity complaints	(113		)	90			120
Other non-current assets and liabilities, net	(4		)	(9		)	14
Net cash provided by operating activities	608			687			556
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(755		)	(750		)	(701		)
Contributions in aid of construction	21			11			17
Other	(10		)	4			(16		)
Net cash used in investing activities	(744		)	(735		)	(700		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt, net of discount	1,199			599			225
Borrowings under revolving credit agreements	1,065			1,042			2,832
Borrowings under term loan credit agreements	250			—			200
Net issuance (repayment) of commercial paper, net of discount	(148		)	48			95
Retirement of long-term debt — including extinguishment of debt costs	(477		)	(139		)	(175		)
Repayments of revolving credit agreements	(1,178		)	(1,028		)	(2,825		)
Repayments of term loan credit agreements	(200		)	(361		)	—
Issuance of common stock	—			13			14
Dividends on common and restricted stock	—			(90		)	(108		)
Dividends to ITC Investment Holdings Inc.	(300		)	(33		)	—
Refundable deposits from generators for transmission network upgrades	16			33			13
Repayment of refundable deposits from generators for transmission network upgrades	(28		)	(10		)	(12		)
Repurchase and retirement of common stock	—			(9		)	(137		)
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		)	(23		)	8
Net cash provided by financing activities	194			42			130
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	58			(6		)	(14		)
CASH AND CASH EQUIVALENTS — Beginning of period	8			14			28
CASH AND CASH EQUIVALENTS — End of period	$	66		$	8		$	14

See notes to consolidated financial statements.

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ITC HOLDINGS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. GENERAL

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

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

2. THE MERGER

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

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

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

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3. RECENT ACCOUNTING PRONOUNCEMENTS

Recently Issued Pronouncements

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

Revenue from Contracts with Customers

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

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

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

Recognition and Measurement of Financial Instruments

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

Accounting for Leases

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

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

Presentation of Restricted Cash in the Statement of Cash Flows

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

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

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

Targeted Improvements to Accounting for Hedging Activities

In August 2017, the FASB issued authoritative guidance to make targeted improvements to hedge accounting to better align with an entity’s risk management objectives and to reduce the complexity of hedge accounting. Among other changes, the new guidance simplifies hedge accounting by (a) allowing more time for entities to complete initial quantitative hedge effectiveness assessments, (b) enabling entities to elect to perform subsequent effectiveness assessments qualitatively, (c) eliminating the concept of recognizing periodic hedge ineffectiveness for cash flow hedges, (d) requiring the change in fair value of a derivative to be recorded in the same income statement line item as the earnings effect of the hedged item, and (e) permitting additional hedge strategies to qualify for hedge accounting. In addition, the guidance modifies existing disclosure requirements and adds new disclosure requirements, including tabular disclosures about both (a) the total amounts reported in the income statement for each income and expense line item that is affected by hedging and (b) the effects of hedging on those line items. The guidance is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early adoption is permitted. The guidance is required to be adopted on a modified retrospective basis to existing hedging relationships and on a prospective basis for the presentation and disclosure requirements. We do not expect a significant impact upon adoption, but we would add the additional required disclosures to the extent we have outstanding hedges upon adoption. We are considering early adoption in 2018.

4. SIGNIFICANT ACCOUNTING POLICIES

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

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

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

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

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

Consolidated Statements of Cash Flows — The following table presents certain supplementary cash flows information for the years ended December 31, 2017, 2016 and 2015:



	Year Ended December 31,
(In millions)	2017		2016		2015
Supplementary cash flows information:
Interest paid (net of interest capitalized) (a)	$	213	$	190	$	191
Income taxes paid (b)	—		23		56
Supplementary non-cash investing and financing activities:
Additions to property, plant and equipment and other long-lived assets (c)	$	87	$	93	$	110
Allowance for equity funds used during construction	33		35		28

____________________________


(a)	Amount for the year ended December 31, 2017 includes $9 million of interest paid associated with the ROE complaints. See Note 17 for information on the ROE complaints.


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


(c)	Amounts consist of current and accrued liabilities for construction, labor, materials and other costs that have not been included in investing activities. These amounts have not been paid for as of December 31, 2017, 2016 or 2015, respectively, but have been or will be included as a cash outflow from investing activities for expenditures for property, plant and equipment when paid.

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

Accounts Receivable — We recognize losses for uncollectible accounts based on specific identification of any such items. As of December 31, 2017 and 2016, we did not have an accounts receivable reserve.

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

Property, Plant and Equipment — Depreciation and amortization expense on property, plant and equipment was $160 million, $149 million and $136 million for 2017, 2016 and 2015, respectively.

Property, plant and equipment in service at our Regulated Operating Subsidiaries is stated at its original cost when first devoted to utility service. The gross book value of assets retired less salvage proceeds is charged to accumulated depreciation. The provision for depreciation of transmission assets is a significant

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component of our Regulated Operating Subsidiaries’ cost of service under FERC-approved rates. Depreciation is computed over the estimated useful lives of the assets using the straight-line method for financial reporting purposes and accelerated methods for income tax reporting purposes. The composite depreciation rate for our Regulated Operating Subsidiaries included in our consolidated statements of operations was 2.0%, 2.0% and 2.1% for 2017, 2016 and 2015, respectively. The composite depreciation rates include depreciation primarily on transmission station equipment, towers, poles and overhead and underground lines that have a useful life ranging from 45 to 60 years. The portion of depreciation expense related to asset removal costs is added to regulatory liabilities or deducted from regulatory assets and removal costs incurred are deducted from regulatory liabilities or added to regulatory assets. Certain of our Regulated Operating Subsidiaries capitalize to property, plant and equipment AFUDC in accordance with the FERC regulations. AFUDC represents the composite cost incurred to fund the construction of assets, including interest expense and a return on equity capital devoted to construction of assets. The interest component of AFUDC of $9 million, $9 million and $7 million was a reduction to interest expense for 2017, 2016 and 2015, respectively.

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

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

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

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

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

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

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

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

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

We completed our annual goodwill impairment test for our reporting units as of October 1, 2017 and determined that no impairment exists. There were no events subsequent to October 1, 2017, including the enactment of the TCJA, that indicated impairment of our goodwill. Our intangible assets other than goodwill have finite lives and are amortized over their useful lives. Refer to Note 7 for additional discussion on our goodwill and intangible assets.

Deferred Financing Fees and Discount or Premium on Debt — Costs related to the issuance of long-term debt are generally recorded as a direct deduction from the carrying amount of the related debt and amortized over the life of the debt issue. Debt issuance costs incurred prior to the associated debt funding are presented as an asset. Unamortized debt issuance costs associated with the revolving credit agreements, commercial paper and other similar arrangements are presented as an asset (regardless of whether there are any amounts outstanding under those credit facilities) and amortized over the life of the particular arrangement. The debt discount or premium related to the issuance of long-term debt is recorded to long-term debt and amortized over the life of the debt issue. We recorded $4 million to interest expense for the amortization of deferred financing fees and debt discounts during each of the years ended December 31, 2017, 2016 and 2015.

Asset Retirement Obligations — A conditional asset retirement obligation is a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within our control. We have identified conditional asset retirement obligations primarily associated with the removal of equipment containing PCBs and asbestos. We record a liability at fair value for a legal asset retirement obligation in the period in which it is incurred. When a new legal obligation is recorded, we capitalize the costs of the liability by increasing the carrying amount of the related long-lived asset. We accrete the liability to its present value each period and depreciate the capitalized cost over the useful life of the related asset. At the end of the asset’s useful life, we settle the obligation for its recorded amount. We recognize regulatory assets for the timing differences between the incurred costs to settle our legal asset retirement obligations and the recognition of such obligations as applicable for our Regulated Operating Subsidiaries. There were no significant changes to our asset retirement obligations in 2017. Our asset retirement obligations as of December 31, 2017 and 2016 of $6 million and $5 million, respectively, are included in other liabilities.

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

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

Revenues — Revenues from the transmission of electricity are recognized as services are provided based on FERC-approved cost-based formula rates. We record a reserve for revenue subject to refund when such refund is probable and can be reasonably estimated. This reserve is recorded as a reduction to operating revenues.

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

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

Refer to Note 14 for additional discussion of the plans.

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

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

The accounting standards for uncertainty in income taxes prescribe a recognition threshold and a measurement attribute for tax positions taken, or expected to be taken, in a tax return that may not be sustainable. As of December 31, 2017, we have not recognized any uncertain income tax positions.

We file income tax returns with the IRS and with various state and city jurisdictions. We are no longer subject to U.S. federal tax examinations for tax years 2012 and earlier. State and city jurisdictions that remain subject to examination range from tax years 2013 to 2016. In the event we are assessed interest or penalties by any income tax jurisdictions, interest and penalties would be recorded as interest expense and other expense, respectively, in our consolidated statements of operations.

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

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5. REGULATORY MATTERS

Cost-Based Formula Rates with True-Up Mechanism

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

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

The net changes in regulatory assets and liabilities associated with our Regulated Operating Subsidiaries’ formula rate revenue accruals and deferrals, including accrued interest, were as follows during the year ended December 31, 2017:



(In millions)	Total
Net regulatory liability as of December 31, 2016	$	(1	)
Net collection of 2015 revenue deferrals and accruals, including accrued interest	(15		)
Net revenue deferral for the year ended December 31, 2017	(17		)
Net accrued interest payable for the year ended December 31, 2017	(2		)
Net regulatory liability as of December 31, 2017	$	(35	)

Regulatory assets and liabilities associated with our Regulated Operating Subsidiaries’ formula rate revenue accruals and deferrals, including accrued interest, are recorded in the consolidated statements of financial position at December 31, 2017 and 2016 as follows:



(In millions)	2017			2016
Current regulatory assets	$	18		$	24
Non-current regulatory assets	11			16
Current regulatory liabilities	(38		)	(9		)
Non-current regulatory liabilities	(26		)	(32		)
Net regulatory liability as of December 31, 2017	$	(35	)	$	(1	)

ITCTransmission Regional Cost Allocation Refund

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

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

MISO Funding Policy for Generator Interconnections

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

MISO Formula Rate Template Modifications Filing

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

Challenge Regarding Bonus Depreciation

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

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

Rate of Return on Equity Complaints

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

6. REGULATORY ASSETS AND LIABILITIES

Regulatory Assets

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



(In millions)	2017		2016
Regulatory Assets:
Current:
Revenue accruals (including accrued interest of less than $1 as of December 31, 2017 and 2016) (a)	$	18	$	24
ITCTransmission regional cost allocation recovery (including accrued interest of less than $1 as of December 31, 2016) (b)	—		29
Total current	18		53
Non-current:
Revenue accruals (including accrued interest of less than $1 as of December 31, 2017 and 2016) (a)	11		16
ITCTransmission ADIT deferral (net of accumulated amortization of $45 and $42 as of December 31, 2017 and 2016, respectively)	16		19
METC ADIT deferral (net of accumulated amortization of $26 and $24 as of December 31, 2017 and 2016, respectively)	17		19
METC regulatory deferrals (net of accumulated amortization of $9 and $8 as of December 31, 2017 and 2016, respectively)	7		8
Income taxes recoverable related to AFUDC equity (c)	80		124
ITC Great Plains start-up, development and pre-construction (net of accumulated amortization of $3 and $2 as of December 31, 2017 and 2016, respectively)	10		11
Pensions and postretirement	30		25
Income taxes recoverable related to implementation of the Michigan Corporate Income Tax and other state excess deficient taxes (c)	7		9
Accrued asset removal costs	19		16
Total non-current	197		247

Total	$	215	$	300

____________________________


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


(b)	Refer to discussion of ITCTransmission regional cost allocation recovery in Note 5 under “ITCTransmission Regional Cost Allocation Refund.”


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

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ITCTransmission ADIT Deferral

The carrying amount of the ITC Transmission ADIT Deferral is the remaining unamortized balance of the portion of ITCTransmission’s purchase price in excess of fair value of net assets acquired from DTE Energy approved for inclusion in future rates by the FERC. The original amount recorded for this regulatory asset of $61 million is recognized in rates and amortized on a straight-line basis over 20 years beginning March 1, 2003. ITCTransmission includes the remaining unamortized balance of this regulatory asset in rate base. ITCTransmission recorded amortization expense of $3 million annually during 2017, 2016 and 2015, which is included in depreciation and amortization and recovered through ITCTransmission’s cost-based formula rate template.

METC ADIT Deferral

The carrying amount of the METC ADIT Deferral is the remaining unamortized balance of the portion of METC’s purchase price in excess of the fair value of net assets acquired at the time MTH acquired METC from Consumers Energy. The original amount approved for recovery recorded for this regulatory asset of $43 million is recognized in rates and amortized on a straight-line basis over 18 years beginning January 1, 2007. METC includes the remaining unamortized balance of this regulatory asset in rate base. METC recorded amortization expense of $2 million annually during 2017, 2016 and 2015, which is included in depreciation and amortization and recovered through METC’s cost-based formula rate template.

METC Regulatory Deferrals

The carrying amount of the METC Regulatory Deferrals is the amount METC has deferred, as a regulatory asset, depreciation and related interest expense associated with new transmission assets placed in service from January 1, 2001 through December 31, 2005 that were included on METC’s balance sheet at the time MTH acquired METC from Consumers Energy. The original amount recorded for this regulatory asset of $15 million, and approved for inclusion in future rates by the FERC, is recognized in rates and amortized over 20 years beginning January 1, 2007. METC includes the remaining unamortized balance of this regulatory asset in rate base. METC recorded amortization expense of $1 million annually during 2017, 2016 and 2015, which is included in depreciation and amortization and recovered through METC’s cost-based formula rate template.

Income Taxes Recoverable Related to AFUDC Equity

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

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

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

Pensions and Postretirement

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

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

In May 2011, the Michigan Business Tax was repealed and replaced with the Michigan Corporate Income Tax, effective January 1, 2012. Under the Michigan Corporate Income Tax, we are taxed at a rate of 6.0% on federal taxable income attributable to our operations in the state of Michigan, subject to certain adjustments. In addition to the traditional income tax, the Michigan Business Tax had also included a modified gross receipts tax that allowed for deductions and credits for certain activities, none of which are part of the Michigan Corporate Income Tax. The change in Michigan tax law required us in 2011 to remove deferred income tax balances recognized under the Michigan Business Tax and establish new deferred income tax balances under the Michigan Corporate Income Tax, and the net result was incremental deferred state income tax liabilities at both ITCTransmission and METC. Under our cost-based formula rate, the future tax receivable as a result of the tax law change has resulted in the recognition of a regulatory asset, which will be collected from customers for the 23-year period and the 32-year period for ITCTransmission and METC, respectively, beginning in 2016. ITCTransmission and METC include this regulatory asset within deferred taxes for rate-making purposes when determining rate base.

Accrued Asset Removal Costs

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

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Regulatory Liabilities

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



(In millions)	2017		2016
Regulatory Liabilities:
Current:
Revenue deferrals (including accrued interest of $2 and less than $1 as of December 31, 2017 and 2016, respectively) (a)	$	38	$	9
Refund related to the formula rate template modifications (including accrued interest of $1 as of December 31, 2016) (b)	—		2
Estimated refund related to return on equity complaints (including accrued interest of $11 and $9 as of December 31, 2017 and 2016, respectively.) (c)	145		118
Total current	183		129
Non-current:
Revenue deferrals (including accrued interest of $1 and $1 as of December 31, 2017 and 2016, respectively) (a)	26		32
Accrued asset removal costs	72		68
Estimated refund related to return on equity complaint (including accrued interest of $6 as of December 31, 2016) (c)	—		140
Excess state income tax deductions (d)	7		9
Income taxes refundable related to implementation of the TCJA (d)	514		—
Total non-current	619		249

Total	$	802	$	378

____________________________


(a)	Refer to discussion of revenue deferrals in Note 5 under “Cost-Based Formula Rates with True-Up Mechanism.” Our Regulated Operating Subsidiaries accrue interest on the true-up amounts which will be refunded through rates along with the principal amount of revenue deferrals in future periods.


(b)	Refer to discussion of the refund in Note 5 under “MISO Formula Rate Template Modifications Filing.”


(c)	Refer to discussion of the refund and estimated refund in Note 17 under “Rate of Return on Equity Complaints.”


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

Accrued Asset Removal Costs

Excess State Income Tax Deductions

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

Income Taxes Refundable Related to Implementation of the TCJA

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35% to 21% effective for tax years beginning after 2017. The Company was required to revalue its deferred tax assets and liabilities at the new federal corporate income tax rate as of the date of the enactment of the TCJA, which resulted in lower net deferred tax liabilities and the establishment of a regulatory liability for excess deferred taxes at our Regulated Operating Subsidiaries. The excess deferred taxes are generally the result of accelerated federal tax deductions realized by our Regulated Operating Subsidiaries in periods when the U.S. federal corporate income tax rate was 35% and now would be returned to customers in a period where the U.S. federal corporate income tax rate is 21%. As the excess deferred taxes must be returned to customers this regulatory liability is recognized. For our Regulated Operating Subsidiaries, our deferred taxes are subject to a normalization method of accounting for the excess tax reserves resulting from the change in the federal statutory tax rate which involves the use of the average rate assumption method (ARAM) for the determination of the timing of the return of the excess deferred taxes to customers associated with public utility property. A portion of our excess deferred taxes at our Regulated Operating Subsidiaries are associated with other types of deferred taxes that are not related to public utility property and the timing of the settlement with customers has not yet been determined. This net regulatory liability is included within deferred taxes for rate-making purposes when determining rate base.

7. GOODWILL AND INTANGIBLE ASSETS

Goodwill

At December 31, 2017 and 2016, we had goodwill balances recorded at ITCTransmission, METC and ITC Midwest of $173 million, $454 million and $323 million, respectively, which resulted from the ITCTransmission and METC acquisitions and ITC Midwest’s acquisition of the IP&L transmission assets, respectively.

Intangible Assets

Pursuant to the METC acquisition in October 2006, we have identified intangible assets with finite lives derived from the portion of regulatory assets recorded on METC’s historical FERC financial statements that were not recorded on METC’s historical GAAP financial statements associated with the METC Regulatory Deferrals and the METC ADIT Deferral as described in Note 6. The carrying amounts of the intangible asset for the METC Regulatory Deferrals and the METC ADIT Deferral were $18 million and $8 million, respectively, as of December 31, 2017, and $20 million and $8 million, respectively, as of December 31, 2016. The amortization periods for the METC Regulatory Deferrals and the METC ADIT Deferral are 20 years and 18 years, respectively, beginning January 1, 2007. METC earns an equity return on the remaining unamortized balance of both intangible assets and recovers the amortization expense through METC’s cost-based formula rate template.

ITC Great Plains has recorded intangible assets for payments made by and obligations of ITC Great Plains to certain TOs to acquire rights, which are required under the SPP tariff to designate ITC Great Plains to build, own and operate projects within the SPP region, including three regional cost sharing projects in Kansas. The carrying amount of these intangible assets was $14 million and $15 million (net of accumulated amortization of $2 million and $1 million, respectively) as of December 31, 2017 and 2016, respectively. The amortization period for these intangible assets is 50 years.

We recorded $1 million of other intangible assets as of December 31, 2017. There were no other intangible assets recorded as of December 31, 2016.

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



(In millions)
2018	$	3
2019	3
2020	3
2021	3
2022	3
2023 and thereafter	25
Total	$	40

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8. PROPERTY, PLANT AND EQUIPMENT

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



(In millions)	2017			2016
Property, plant and equipment
Regulated Operating Subsidiaries:
Property, plant and equipment in service	$	8,334		$	7,715
Construction work in progress	546			455
Capital equipment inventory	74			74
Other	16			15
ITC Holdings and other	14			14
Total	8,984			8,273
Less: Accumulated depreciation and amortization	(1,675		)	(1,575		)
Property, plant and equipment — net	$	7,309		$	6,698

Additions to property, plant and equipment in service and construction work in progress during 2017 and 2016 were due primarily for projects to upgrade or replace existing transmission plant to improve the reliability of our transmission systems as well as transmission infrastructure to support generator interconnections and investments that provide regional benefits such as our Multi-Value Projects.

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9. DEBT

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



(In millions)	2017			2016
ITC Holdings 6.23% Senior Notes, Series B, due September 20, 2017 (a)	$	—		$	50
ITC Holdings 6.375% Senior Notes, due September 30, 2036	200			200
ITC Holdings 6.05% Senior Notes, due January 31, 2018 (b)	—			385
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			—
ITC Holdings 3.35% Senior Notes, due November 15, 2027	500			—
ITC Holdings Revolving Credit Agreement, due October 21, 2022 (c)	—			73
ITC Holdings Commercial Paper Program (a)	—			145
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 (a)	100			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 Term Loan Credit Agreement, due March 23, 2019	50			—
ITCTransmission Revolving Credit Agreement, due October 21, 2022 (c)	36			44
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 (c)	48			31
ITC Midwest 6.15% First Mortgage Bonds, Series A, due January 31, 2038	175			175
ITC Midwest 7.12% First Mortgage Bonds, Series B, due December 22, 2017 (a)	—			40
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			—
ITC Midwest Revolving Credit Agreement, due October 21, 2022 (c)	88			127
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 (c)	49			59
Total principal	5,141			4,624
Unamortized deferred financing fees and discount	(40		)	(34		)
Total debt	$	5,101		$	4,590

____________________________


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


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

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

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



(In millions)
2018	$	100
2019	50
2020	235
2021	—
2022	721
2023 and thereafter	4,035
Total	$	5,141

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. The 2017 Senior Notes were issued under ITC Holdings’ indenture, dated April 18, 2013.

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

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

Commercial Paper Program

ITC Holdings has an ongoing commercial paper program for the issuance and sale of unsecured commercial paper in an aggregate amount not to exceed $400 million outstanding at any one time. As of December 31, 2017, ITC Holdings did not have any commercial paper issued or outstanding. The proceeds from issuances under the program during the year ended December 31, 2017 were used to repay and retire the $50 million of ITC Holdings’

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

Term Loan Credit Agreement

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

METC

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

ITC Midwest

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

ITCTransmission

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

Derivative Instruments and Hedging Activities

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

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



Interest Rate Swaps (In millions, except percentages)	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, 2017, ITC Holdings did not have any interest rate swaps outstanding.

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Revolving Credit Agreements

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



(In millions, except percentages)	Total Available Capacity		Outstanding Balance (a)		Unused Capacity			Weighted Average Interest Rate on Outstanding Balance		Commitment Fee Rate (b)
ITC Holdings	$	400	$	—	$	400	(c)	—%	(d)	0.175	%
ITCTransmission	100		36		64			2.5%	(e)	0.10	%
METC	100		48		52			2.5%	(e)	0.10	%
ITC Midwest	225		88		137			2.5%	(e)	0.10	%
ITC Great Plains	75		49		26			2.5%	(e)	0.10	%
Total	$	900	$	221	$	679

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(a)	Included within long-term debt.


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


(c)	ITC Holdings’ revolving credit agreement may be used for general corporate purposes, including to repay commercial paper issued pursuant to the commercial paper program described above, if necessary. At December 31, 2017 ITC Holdings did not have any commercial paper issued or outstanding.


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


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

Covenants

Our debt instruments contain numerous financial and operating covenants that place significant restrictions on certain transactions, such as incurring additional indebtedness, engaging in sale and lease-back transactions, creating liens or other encumbrances, entering into mergers, consolidations, liquidations or dissolutions, creating or acquiring subsidiaries, selling or otherwise disposing of all or substantially all of our assets and paying dividends. In addition, the covenants require us to meet certain financial ratios, such as maintaining certain net debt to capitalization ratios and certain funds from operations to net debt levels. As of December 31, 2017, we were not in violation of any debt covenant.

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10. INCOME TAXES

Our effective tax rate varied from the statutory federal income tax rate due to differences between the book and tax treatment of various transactions as follows:



(In millions)	2017			2016			2015
Income tax expense at 35% statutory rate	$	180		$	120		$	134
State income taxes (net of federal benefit) (a)	16			3			14
AFUDC equity	(10		)	(11		)	(8		)
Revaluation of deferred federal income taxes (b)	8			—			—
Excess tax deductions for share-based compensation (c)	—			(23		)	—
Other — net (d)	2			8			2
Total income tax provision	$	196		$	97		$	142

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(a)	Amount for the year ended December 31, 2017 includes income tax benefits of $3 million related to the revaluation of state deferred tax assets and liabilities for the net of federal benefit impact of the TCJA.


(b)	Amount for the year ended December 31, 2017 represents income tax expense related to the revaluation of federal deferred tax assets and liabilities as a result of the TCJA.


(c)	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.


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

Components of the income tax provision were as follows:



(In millions)	2017		2016			2015
Current income tax expense (benefit) (a)	$	1	$	(122	)	$	65
Deferred income tax expense (b)(c)(d)	195		219			77
Total income tax provision	$	196	$	97		$	142

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(a)	Amount for the year ended December 31, 2016 primarily relates to the cash benefit that resulted from the election of bonus depreciation as described in Note 5.


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


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


(d)	Amount for the year ended December 31, 2016 includes utilization of $126 million of net operating losses, primarily resulting from the election of bonus depreciation as described in Note 5.

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

In December 2017, the President of the United States signed into law the TCJA, which enacted significant changes to the Internal Revenue Code including a reduction in the U.S. federal corporate income tax rate from 35% to 21% effective for tax years beginning after 2017. The revaluation of the deferred tax assets and federal income tax net operating losses at ITC Holdings has resulted in additional income tax expense in the fourth quarter of 2017 of $5 million. For additional information on the impacts of tax reform, see Note 6.

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

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

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

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

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



(In millions)	2017			2016
Property, plant and equipment	$	(798	)	$	(1,026	)
Federal income tax NOLs and other credits	84			140
METC regulatory deferral (a)	(6		)	(11		)
Acquisition adjustments — ADIT deferrals (a)	(10		)	(15		)
Goodwill	(120		)	(163		)
ITCTransmission regional cost allocation recovery (b)	—			(11		)
Refund liabilities (a)	38			56
Regulatory liability gross up - TCJA	139			—
Pension and postretirement liabilities	16			23
State income tax NOLs (net of federal benefit) (c)	50			47
True-up adjustment principal & interest	9			1
Other — net	(3		)	(5		)
Net deferred tax liabilities (d)	$	(601	)	$	(964	)
Gross deferred income tax liabilities	$	(952	)	$	(1,252	)
Gross deferred income tax assets	351			288
Net deferred tax liabilities	$	(601	)	$	(964	)

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(a)	Described in Note 6.


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


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

(d)

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

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

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

11. RETIREMENT BENEFITS AND ASSETS HELD IN TRUST

Pension Plan Benefits

We have a qualified defined benefit pension plan (“retirement plan”) for eligible employees, comprised of a traditional final average pay plan and a cash balance plan. The traditional final average pay plan is noncontributory, covers select employees, and provides retirement benefits based on years of benefit service, average final compensation and age at retirement. The cash balance plan is also noncontributory, covers substantially all employees and provides retirement benefits based on eligible compensation and interest credits. Our funding practice for the retirement plan is to contribute amounts necessary to meet the minimum funding requirements of the Employee Retirement Income Security Act of 1974, plus additional amounts as we determine appropriate. We made contributions of $4 million, $3 million and $4 million to the retirement plan in 2017, 2016 and 2015, respectively. We expect to contribute $4 million to the retirement plan in 2018.

We also have two supplemental nonqualified, noncontributory, defined benefit pension plans for selected management employees (the “supplemental benefit plans” and collectively with the retirement plan, the “pension plans”). The supplemental benefit plans provide for benefits that supplement those provided by the retirement plan. The obligations under these supplemental benefit plans are included in the pension benefit obligation calculations below. The investments held in trust for the supplemental benefit plans of $53 million and $42 million at December 31, 2017 and 2016, respectively, are not included in the plan asset amounts presented below, but are included in other assets on our consolidated statements of financial position. For the years ended December 31, 2017, 2016 and 2015, we contributed $14 million, $5 million and $9 million, respectively, to these supplemental benefit plans.

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

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



Asset Category	2017		2016
Fixed income securities	50.2	%	50.3	%
Equity securities	49.8	%	49.7	%
Total	100.0	%	100.0	%

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



(In millions)	2017			2016			2015
Service cost	$	6		$	6		$	6
Interest cost	4			4			4
Expected return on plan assets	(4		)	(4		)	(3		)
Amortization of unrecognized loss	1			4			4
Net pension cost	$	7		$	10		$	11

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

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



(In millions)	2017			2016
Change in Benefit Obligation:
Beginning projected benefit obligation	$	(116	)	$	(97	)
Service cost	(6		)	(6		)
Interest cost	(4		)	(4		)
Actuarial net loss	(7		)	(11		)
Benefits paid	6			2
Ending projected benefit obligation	(127		)	(116		)
Change in Plan Assets:
Beginning plan assets at fair value	64			58
Actual return on plan assets	9			5
Employer contributions	4			3
Benefits paid	(2		)	(2		)
Ending plan assets at fair value	75			64
Funded status, underfunded	$	(52	)	$	(52	)
Accumulated benefit obligation:
Retirement plan	$	(67	)	$	(56	)
Supplemental benefit plans	(56		)	(55		)
Total accumulated benefit obligation	$	(123	)	$	(111	)
Amounts recorded as:
Funded Status:
Accrued pension liabilities	$	(54	)	$	(52	)
Other non-current assets	6			4
Other current liabilities	(4		)	(4		)
Total	$	(52	)	$	(52	)
Unrecognized Amounts in Non-current Regulatory Assets:
Net actuarial loss	$	26		$	25
Total	$	26		$	25

Actuarial assumptions used to determine the benefit obligation for the pension plans at December 31, 2017, 2016 and 2015 are as follows:



	2017	2016	2015
Weighted average discount rate (a)	3.57%	4.00%	4.26%
Annual rate of salary increases	4.00%	4.00%	4.00%

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

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Actuarial assumptions used to determine the benefit cost for the pension plans for the years ended December 31, 2017, 2016 and 2015 are as follows:



	2017	2016	2015
Weighted average discount rate — service cost (a)	4.20%	4.46%	3.95%
Weighted average discount rate — interest cost (a)	3.45%	3.62%	3.95%
Annual rate of salary increases	4.00%	4.00%	4.00%
Expected long-term rate of return on plan assets	6.20%	6.40%	6.70%

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

At December 31, 2017, the projected benefit payments for the pension plans calculated using the same assumptions as those used to calculate the benefit obligation described above are as follows:



(In millions)
2018	$	6
2019	6
2020	7
2021	7
2022	7
2023 through 2027	47

Investment Objectives and Fair Value Measurement

The general investment objectives of the retirement plan include maximizing the return within reasonable and prudent levels of risk and controlling administrative and management costs. The targeted asset allocation is weighted equally between equity and fixed income investments. Investment decisions are made by our retirement benefits board as delegated by our board of directors. Equity investments may include various types of U.S. and international equity securities, such as large-cap, mid-cap and small-cap stocks. Fixed income investments may include cash and short-term instruments, U.S. Government securities, corporate bonds, mortgages and other fixed income investments. No investments are prohibited for use in the retirement plan, including derivatives, but our exposure to derivatives currently is not material. We intend that the long-term capital growth of the retirement plan, together with employer contributions, will provide for the payment of the benefit obligations.

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

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

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



	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 fair value measurement of the retirement plan assets as of December 31, 2016, 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	$	25	$	—	$	—
Mutual funds — international equity securities	7		—		—
Mutual funds — fixed income securities	32		—		—
Total	$	64	$	—	$	—

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

Category

Goal

Rationale for Goal

Rationale for Target Goal

Potential Payout

2017 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 2016 and based on the 2017 Board-approved budget.

Non-Field O&M and G&A expense at or under budget of $147 million.

$137.1 million

10%

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 2017 Board-approved budget.

Net Income from our Regulated Operating Subsidiaries (excluding ITC Interconnection) at or above $414 million to achieve 10%;
Net Income at or above $393 million to achieve 5%.

5% - 10%

$406.1 million

Total

15%

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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		2017 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	5	%	2	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.	5	%	5	5%
	Infrastructure Protection	Maintaining cyber and physical security is critical to ensuring system reliability and ongoing operations.	Goal focused on implementing updated cyber-security and physical security plans. Emphasized securing our information systems and our most important assets. Implementation of the 2017 Cyber Security and CIP (critical infrastructure protection) Plan and the Physical Security Plan, as presented to and approved by the Board of Directors, each plan 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 System Development.



Category	Goal	Rationale for Goal	Rationale for Target	Potential Payout		2017 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 unchanged from prior year. Number of Forced, Sustained Line Outages, excluding the "External" cause classification, for: ITCTransmission (16 or fewer, representing top decile performance); METC (31 or fewer, representing top decile performance); ITC Midwest (70 or fewer, representing second quartile performance, no more than 59 of which can cause end-use customer sustained outages); Each target worth 5%.	15	%	ITCTransmission - 10 METC - 18 ITC Midwest - 58/ 49	15%
	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 2017 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 expenditures. The maximum payout represents the risk-adjusted capital investment plan for 2017, with a threshold level also established. Complete $710M of the 2017 Capital Expenditure budget to achieve 30%; Complete $674M to achieve 15%.	15 - 30%		$777.6 million	30%
				60	%		60%

Total Bonus (as a percent of target bonus level)				100	%		95%

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

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



Measure	Threshold	Achievement	Multiplier	Weight	Result
Capital Project Plan	$710M	$777.6M	2.00x	50%	1.00x
Consolidated Net Income	$331M	$323.8M	1.00x	25%	0.25x
Cash Flow Available for Distribution	$266M	$300M	2.00x	25%	0.50x
Bonus Multiplier					1.75x

Each measure has an established scale, which includes a threshold level and below equating to a 1.00x multiplier, having no impact on the bonus award, to a maximum of 2.00x, which would increase the bonus by 100%. Achievement against performance scales related to each of the above metrics produced an executive bonus multiplier of 1.75x. This performance factor was applied to each executive’s annual corporate performance bonus to produce a final payment of approximately 166.3% of target.

Bonuses are based on a target bonus, which for each executive is a percentage of his or her base salary. The Committee considers each individual’s job responsibilities and the results of its benchmarking analysis when determining the base bonus percentage for the executive officers, including the NEOs, which we refer to as the “target bonus levels”. Target bonus levels for 2017 were as follows:



NEO	% of Base Salary
Linda H. Apsey	100	%
Gretchen Holloway	100	%
Jon E. Jipping	100	%
Daniel J. Oginsky	100	%
Christine Mason Soneral	100	%

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

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

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Long-Term Incentives

The Committee provides and maintains a long-term incentive program under the 2017 Omnibus Plan, as amended July 10, 2017 (the “2017 Omnibus Plan”). In February 2017, the Committee approved grants of service-based units and performance-based units to employees, including the NEOs, based on our CEO’s recommendation (except for grants to the CEO), and also on the Committee’s assessment of the performance of the Company and the executive. Award opportunities for the NEOs were provided in a mix of performance-based units (weighted 67%) and service-based units (weighted 33%). The performance-based units can be earned for results in two equally-weighted measures, Total Shareholder Return (relative to a peer group) and cumulative consolidated net income, over the three-year performance period. Each unit is generally equivalent to one share of Fortis stock (as traded on the Toronto Stock Exchange) and earned units are payable in cash. Awards to the CEO were also presented to the Board of Directors by the Committee and ratified by the Board of Directors. The amounts and more detailed terms of the 2017 service-based unit and performance-based unit grants made under the 2017 Omnibus Plan are described in the narrative following the Grants of Plan-Based Awards Table. The awards were designed to reward, motivate and encourage long-term performance, act as a retention mechanism, and further align the interests of the NEOs with the interests of the shareholder. Total value for the award for each grantee was determined based on a percentage of salary. For the NEOs, when the 2017 awards were made, the award values were targeted to be:



NEO	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 that plan. The Committee exercises no regular discretionary authority in the determination of benefits. The retirement plans may be modified, amended or terminated at any time, although no such action may reduce a NEO’s earned benefits. See “Pension Benefits” for information regarding participation by the NEOs in our retirement plans as well as a description of the terms of the plans.

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

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

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hours for such personal travel. Ms. Apsey incurs imputed income for all guests and herself for personal travel in the amount of the incremental cost to the Company of such travel.

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

None of the NEOs are reimbursed for income taxes associated with the value of the perquisites. Our employment agreements provide for limited tax gross-ups following termination in some circumstances. The Committee continues to monitor and review the Company’s perquisite program. Perquisites are further discussed in footnote 5 to the Summary Compensation Table.

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

Recoupment Policy

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

•

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


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

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

Retention Program

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



NEO	Retention Award
Linda Apsey	$	921,000
Gretchen Holloway	200,000
Jon Jipping	753,000
Daniel Oginsky	634,500
Christine Mason Soneral	525,000

Employment Agreement Amendment — Mason Soneral

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

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

Governance and Human Resources Committee Report

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

RHYS D. EVENDEN 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 ($) (2)		Option Awards ($) (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)		(j)
Linda H. Apsey, President & CEO	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
	2015	616,362		222,164		744,344		342,146		598,650		41,875		37,990		2,603,531

Gretchen L. Holloway SVP & CFO (6)	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	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
	2015	503,931		207,775		608,587		279,734		489,450		82,651		36,010		2,208,138

Daniel J. Oginsky, EVP & CAO	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
	2015	424,627		153,055		512,812		235,714		412,425		13,883		26,869		1,779,385

Christine Mason Soneral, SVP & General Counsel	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
	2015	$	328,777	$	38,861	$	775,093	$	195,034	$	341,250	$	112,077	$	13,950	$	1,805,042

____________________________

(1)

The compensation amounts reported in this column include, (a) awards under the Special Bonus Plan, (b) bonuses paid in connection with project milestones and (c) retention bonuses. Bonuses paid in connection with our annual corporate performance plan are reported in the “Non-Equity Incentive Plan Compensation” column of the Summary Compensation Table. Bonuses under the Special Bonus Plan, were awarded at the sole discretion of the Committee and were equal to per share dividend amounts paid by the Company multiplied by the number of options granted in 2003 and 2005. These options were exercised and the Special Bonus Plan expired in 2015. In 2015 and 2016, the NEOs, received certain project-related bonuses in recognition of the successful completion of various transmission development milestones. In 2016, Ms. Mason Soneral received $300,000 since the Merger was closed before December 31, 2016. In 2016, all of the NEOs received 30% of their retention award due to the closing of the Merger and, in October 2017, they received the remaining 70% of their retention award. See “Compensation Discussion and Analysis - Retention Program”. In 2017, Ms. Mason Soneral earned $162,399 in accordance with the retention payments related to her employment agreement amendment. See “Compensation Discussion and Analysis - Employment Agreement Amendment - Mason Soneral”. In 2017, Ms. Holloway received a lump sum payment of $125,000 and Mr. Jipping received a lump sum payment of $11,000 due to their expanding responsibilities. These bonuses are set forth in the following table.

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Name	Year	Special Bonus ($)		Retention Bonus ($)		Merger Completion ($)		Other Bonuses ($)			Total Bonus ($)

Linda H. Apsey	2017	$	—	$	644,700	$	—	$	—		$	644,700
	2016	—		276,300		—		383,362			659,662
	2015	—		—		—		222,164			222,164
Gretchen L. Holloway	2017	—		140,000		—		125,000			265,000
Gretchen L. Holloway	2016	—		60,000		—		—			60,000
Jon E. Jipping	2017	—		527,100		—		11,000			538,100
	2016	—		225,900		—		313,433			539,333
	2015	26,136		—		—		181,639			207,775
Daniel J. Oginsky	2017	—		444,150		—		—		—	444,150
	2016	—		190,350		—		264,108			454,458
	2015	—		—		—		153,055			153,055
Christine Mason Soneral	2017	—		529,899		—		—			529,899
	2016	—		157,500		300,000		67,057			524,557
	2015	$	—	$	—	$	—	$	38,861		$	38,861


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

The grant date fair value of the service-based unit awards is based on the applicable share price on the grant date. The grant date fair value of the performance-based units is based on the applicable share price on the grant date and the expected payout of the performance and market conditions, with the market condition fair value determined using a Monte Carlo simulation valuation model. The service-based unit awards and performance-based unit awards are liability awards, subject to remeasurement through the vesting date, and settled in cash, see “Grants of Plan-Based Awards”. The 2016 awards only included restricted shares; performance shares and restricted shares were awarded in 2015.

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



Year	Remaining Future Life of Option	Expected Volatility		Risk Free Interest Rate		Expected Life (Years)	Expected Dividend Yield		Share Price at Grant Date

2017	—	—	%	—	%	—	—	%	$	—
2016	—	—	%	—	%	—	—	%	$	—
2015	7.3	18.6	%	1.81	%	6	1.59	%	$	35.91


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

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


(5)	All Other Compensation includes amounts for auto allowance, financial, estate and legal planning, income tax return preparation, annual physical, club memberships, event tickets, personal liability insurance,

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personal use of company aircraft and for other benefits such as Company contributions on behalf of the NEOs pursuant to the matching component of the Savings and Investment Plan. Perquisites have been valued for purposes of these tables on the basis of the aggregate incremental cost to the Company. The incremental cost of the personal use of the Company aircraft was determined based upon the Company’s expenses incurred in connection with the actual costs of maintenance, landing, parking, crew and catering and estimated fuel costs relating to Ms. Apsey’s hours of use of the plane. Fuel expense was determined by calculating the average fuel cost for the month and the average amount of fuel used per hour. These benefits and perquisites for 2017, 2016 and 2015 are itemized in the table below as required by applicable SEC rules.



Name	Year	401(k) Match		Tax Reimbursements		Personal Use of Company Aircraft		Other Benefits		Total
Linda H. Apsey	2017	$	14,400	$	—	$	12,752	$	30,599	$	57,751
	2016	14,300		—		—		27,001		41,301
	2015	14,300		—		—		23,690		37,990
Gretchen L. Holloway	2017	14,400		—		—		18,726		33,126
Gretchen L. Holloway	2016	14,300		—		—		17,012		31,312
Jon E. Jipping	2017	16,200		—		—		21,494		37,694
	2016	15,900		—		—		21,369		37,269
	2015	14,300		—		—		21,710		36,010
Daniel J. Oginsky	2017	14,400		—		—		21,572		35,972
	2016	14,300		—		—		21,197		35,497
	2015	14,300		—		—		12,569		26,869
Christine Mason Soneral	2017	14,400		—		—		21,978		36,378
	2016	14,300		—		—		21,375		35,675
	2015	$	13,950	$	—	$	—	$	—	$	13,950


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

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Grants of Plan-Based Awards

The following table sets forth information concerning each grant of an award made to a NEO during 2017. In this table, a service-based unit is referred to as an “SBU”, a performance-based unit is referred to as a “PBU” and an award under the annual corporate performance bonus plan is referred to as an “ACPB”.

Grants of Plan-Based Awards Table



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 ($)(3)
Name	Grant Date	Award Type	Threshold ($)		Target ($)(1)		Maximum ($)(1)		Threshold (#)		Target (#)(2)		Maximum (#)(2)		Grant Date Fair Value of Stock and Option Awards ($)(3)
(a)	(b)		(c)		(d)		(e)		(f)		(g)		(h)	(i)	(j)
Linda H. Apsey	3/8/2017	SBU	$	—	$	—	$	—	—		—	—	—	19,590	$	617,826
	3/8/2017	PBU	—		—		—		19,590	—	39,181	—	78,362	—	1,143,008
		ACPB	—		725,000		1,450,000		—	—	—	—	—	—	—
Gretchen L. Holloway	3/8/2017	SBU	—		—		—		—	—	—	—	—	6,147	193,863
	3/8/2017	PBU	—		—		—		6,147	—	12,295	—	24,590	—	358,676
		ACPB	—		350,000		700,000		—	—	—	—	—	—	—
Jon E. Jipping	3/8/2017	SBU	—		—		—		—	—	—	—	—	10,119	319,131
	3/8/2017	PBU	—		—		—		10,119	—	20,239	—	40,478	—	590,422
		ACPB	—		535,000		1,070,000		—	—	—	—	—	—	—
Daniel J. Oginsky	3/8/2017	SBU	—		—		—		—	—	—	—	—	8,512	268,450
	3/8/2017	PBU	—		—		—		8,511	—	17,023	—	34,046	—	496,603
		ACPB	—		450,000		900,000		—	—	—	—	—	—	—
Christine Mason Soneral	3/8/2017	SBU	—		—		—		—	—	—	—	—	6,904	217,737
	3/8/2017	PBU	—		—		—		6,904	—	13,808	—	27,616	—	402,814
		ACPB	$	—	$	365,000	$	730,000	—	—	—	—	—	—	$	—

____________________________

(1)

The amount shown in Column (d) represents the potential payout for the annual corporate performance bonus based on “target bonus levels”. The amount payable assuming maximum achievement of all bonus goals is set forth in column (e). Actual dollar amounts paid are disclosed and reported in the Summary Compensation Table as Non-Equity Incentive Plan Compensation. For more information regarding the annual corporate performance bonuses, see “Compensation Discussion and Analysis — Key Components of Our NEO Compensation Program — Annual Corporate Performance Bonus.”

(2)

Payment of each performance-based unit award is contingent on meeting performance targets based on (1) Fortis Total Shareholder Return in comparison to the Total Shareholder Return during the performance period for each of the companies that comprise the 2017 Fortis peer group and (2) cumulative consolidated net income for each fiscal year during the performance period. The performance measures are independent of each other. If threshold, target or maximum performance goals are attained in the performance period, 50%, 100% or 200% of the target amount, respectively, may be earned. If actual performance falls between threshold, target and maximum, the awards would be prorated between levels based on performance outcome. For more information regarding performance share awards, see “Grant of Plan-Based Awards - Performance-Based Unit Award Agreement.”

(3)

Grant Date Fair Value consists of service-based units and performance-based units awarded under the 2017 Omnibus Plan with a grant date of March 8, 2017. The performance-based units reflected here are recorded at fair value at the date of grant, which was $29.17 per share. The service-based units reflected here are recorded at fair value at the date of grant, which was $31.53 per share. Share fair values were converted from Canadian Dollars to US Dollars using the “Award Conversion Rate” defined in the 2017 Omnibus Plan.

The Committee has established long-term incentive targets as a percentage of the base salary for each NEO in consideration of benchmarking data on total direct compensation, the importance of the NEO’s position to the success of the Company, our need to create meaningful incentives to enhance performance and the culture of

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teamwork that makes our company successful. The Committee did not have a pre-established targeted allocation of total direct compensation.

The Committee had the power to award service-based units and performance-based units in the form of equity or cash under the 2017 Omnibus Plan with the terms of each award set forth in a written agreement with the recipient. Grants made in 2017 to the NEOs were made under the 2017 Omnibus Plan pursuant to terms stated in the service-based unit and performance-based unit award agreements.

Performance-Based Unit Award Agreements

The performance-based unit award agreements entered into with each NEO in 2017 (each a “PBU Agreement”) provide generally that the award will vest on December 31, 2019 (the “Vesting Date”) to the extent one or more of the performance goals are met and if the grantee continues to be employed by the Company through the Vesting Date. One-half of the Target Number of units shall be related to the Fortis Total Shareholder Return goal (the “TSR goal”) and one-half of the Target Number of shares shall be related to the Cumulative Consolidated Net Income goal (the “CCNI goal”). The PBUs will become earned as set forth in the following table:



Measurement Category	Goal at Threshold	Shares at Threshold	Goal at Target	Shares at Target	Goal at Maximum	Shares at Maximum
Fortis Total Shareholder Return	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, 2017 through December 31, 2019 (the “Payment Criteria Period”). The performance measures are independent of each other; that is, if the threshold level of one performance measure is attained, units relating to that measure will be “earned” (subject to vesting as otherwise provided in the PBU Agreement) even if the threshold level of the other performance measure is not attained. The number of performance-based units that are “earned” with respect to each performance measure will be prorated between levels based on performance. The Committee will have discretion to reduce the number of units earned under certain circumstances.

Total Shareholder Return of Fortis will be compared to each of the companies (the “Peer Companies”) listed in the Fortis Peer Group 2017 Report excluding any company that is no longer traded on the Toronto Stock Exchange or a “national securities exchange” at the end of the Payment Criteria Period. The Peer Companies currently consist of the following 25 U.S. and Canadian public utility companies:



Alliant Energy	Emera Inc.	Pinnacle West Capital
Ameren Corp.	Energy Corp.	PPL Corp.
Atmos Energy Corp.	Eversource Energy	Public Svc Enterprise Group
Canadian Utilities Ltd.	FirstEnergy Corp.	SCANA Corp.
CenterPoint Energy Inc.	Great Plains Energy Inc.	Sempre Energy
CMS Energy Corp.	Hydro One Ltd.	UGI Corp.
Consolidated Edison Inc.	NiSource Inc.	WEC Energy Group
DTE Energy Co.	OGE Energy Corp.	Xcel Energy
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

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report on Form 10-K for such year, as adjusted for extraordinary items and changes in Return on Equity, in each case in the Committee’s discretion. Cumulative Consolidated Net Income for the Company during the Payment Criteria Period shall be the sum of the Consolidated Net Income for each of the three years in the Payment Criteria Period.

If the grantee ceases to be employed before the Vesting Date due to death or disability, the grantee will receive, following the Vesting Date, the number of units to which the grantee would have otherwise been entitled if the grantee had remained employed through the Vesting Date. If the grantee ceases to be employed before the Vesting Date due to “Retirement” or “Involuntary Termination Without Cause,” and the grantee has been in service of the Company for one year or more after the grant date, the grantee will receive, following the Vesting Date, a pro rata portion (based on the period served from the grant date to termination) of the number of units to which the grantee would have otherwise been entitled. If termination occurs prior to the Vesting Date other than as a result of death, disability, Retirement or Involuntary Termination Without Cause, grantee will forfeit the award. “Involuntary Termination Without Cause” means a termination of the grantee’s employment by the Company other than due to the grantee’s death, disability, Retirement, voluntary resignation or for “Cause” (as defined in the PBU Agreement). “Retirement” is defined to mean termination of grantee’s employment with the Company upon or after attaining “normal retirement age” (as defined in the International Transmission Company Retirement Plan”).

Upon a “Change of Control”, as defined in the 2017 Omnibus Plan, all outstanding performance-based units become redeemable on the trading day that is immediately prior to the effective date of the consummation of the event resulting in the Change of Control (the “Change of Control Redemption Date”). In the event of a Change of Control, the payout percentage for outstanding performance-based units is the product of (i) the higher of (A) 100% of the target number of performance-based units in the award or (B) the actual payout percentage based on the Committee’s assessment of performance of the payment criteria from the beginning of the Payment Criteria Period for the award through the date of the Change of Control, multiplied by (ii) a fraction, the numerator of which is the number of days elapsed in the Payment Criteria Period for the award through the date on which the Change of Control occurred and the denominator of which is the total number of days in the payment criteria period for the award.

Grantees are entitled to receive additional units equal to the “dividend equivalent” when a cash dividend is paid on common shares of Fortis stock (each a “Common Share”). Such “dividend equivalent” shall be equal to a fraction where the numerator is the product of (a) the number of performance-based units in the grantee’s account on the date that the dividends are paid, including performance-based units previously credited as “dividend equivalents,” multiplied by (b) the dividend paid per Common Share and the denominator of which is the “Market Price” of one Common Share calculated on the date that dividends are paid, converted to U.S. dollars based on the Award Conversion Rate. All “dividend equivalent” performance-based units shall have a Vesting Date which is the same as the Vesting Date for the performance-based units in respect of which such additional performance-based units are credited.

Service-Based Unit Award Agreements

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

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Outstanding Equity Awards at Fiscal Year-End

The following table provides information with respect to service-based units and performance-based units that have not vested as of the end of 2017 held by the NEOs.



Name	Number of Shares or Units of Stock That Have Not Vested (#) (SBUs) (2)	Market Value of Shares or Units of Stock That Have Not Vested ($) (SBUs) (1)		Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#) (PBUs) (3)	Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($) (PBUs) (1)
(a)	(b)	(c)		(d)	(e)
Linda H. Apsey	20,117	$	737,707	40,236	$	1,475,451
Gretchen L. Holloway	6,313	231,479		12,626	462,997
Jon E. Jipping	10,391	381,054		20,784	762,146
Daniel J. Oginsky	8,741	320,539		17,481	641,040
Christine Mason Soneral	7,090	$	259,986	14,180	$	519,972

(1) Value was determined by multiplying the number of units that have not vested by the closing price of Fortis common stock as of December 29, 2017 ($36.67).

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

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

Equity grants made to NEOs in 2017 were made pursuant to the 2017 Omnibus Plan. The terms of the grants are described above in the narrative discussion accompanying the Grants of Plan-Based Awards Table.

Option Exercises and Stock Vested

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

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Pension Benefits

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

Pension Benefits Table



Name	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	23.58	$	373,576	N/A
	ESRP Shift	N/A	36,447		N/A
	Total Qualified Plan		410,023		N/A
	ESRP	14.83	1,422,819		N/A
Gretchen Holloway	Cash Balance Component	13.95	235,678		N/A
	Total Qualified Plan		235,678		N/A
	ESRP	2.91	100,652		N/A
Jon E. Jipping	Traditional Component	27.03	1,410,494		N/A
	Total Qualified Plan		1,410,494		N/A
	ESRP	12.92	1,203,671		N/A
Daniel J. Oginsky	Cash Balance Component	13.20	298,264		N/A
	Total Qualified Plan		298,264		N/A
	ESRP	13.20	957,202		N/A
Christine Mason Soneral	Cash Balance Component	10.29	231,647		N/A
	Total Qualified Plan		231,647		N/A
	ESRP	10.29	$	475,595	N/A

____________________________


(1)	Credited service is estimated as of December 31, 2017 and represents the service reflected in the determination of benefits. For determining vesting, service with DTE Energy is counted for the Qualified Plan only.

For Ms. Apsey and Mr. Jipping, the credited service for the cash balance and traditional components of the Qualified Plan, respectively, includes service with DTE Energy. The Company began operations on February 28, 2003, following its acquisition of ITCTransmission from DTE Energy. As of that date, the benefits from DTE Energy’s qualified plan that had accrued, as well as the associated assets from DTE Energy’s pension trust, were transferred to the Qualified Plan. Therefore, even though DTE Energy service is included in determining the benefits under the traditional and cash balance components of the Qualified Plan, the benefits associated with this additional service do not represent a benefit augmentation, but rather a transfer of benefit liability and associated assets from DTE Energy’s qualified plan to the Qualified Plan. With respect to the ESRP, credited service includes Company service only for the period during which the NEO was an ESRP participant.

(2)

The “Present Value of Accumulated Benefit” is the estimated lump-sum equivalent value measured as of December 31, 2017 (the “measurement date” used for financial accounting purposes) of the benefit that was earned as of that date. Certain benefits are payable as an annuity only, not as a lump sum, and/or may not be payable for several years in the future. The values reflected are based on several assumptions. The date at which the present values were estimated was December 31, 2017. The rate at which future expected benefit payments were discounted in calculating present values was 3.67%, the same rate used for fiscal year-end 2017 financial accounting disclosure of the Qualified Plan. The future annual earnings rate on account balances under the cash balance and ESRP shift components of the Qualified Plan, and for ESRP benefits, was assumed to be 2.78% for 2018 and 4.5% thereafter.

We assumed no NEOs would die or become disabled prior to retirement, or terminate employment with us prior to becoming eligible for benefits unreduced for early retirement. The assumed retirement age for each

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executive was generally the earliest age at which benefits unreduced for early retirement were available under the respective plans. For the traditional component of the defined benefit plan, that age is the earlier of (1) age 58 with 30 years of service (including service with DTE Energy), or (2) age 60 with 15 years of service. For consistency, we generally use the same assumed retirement commencement age for other benefits, including benefits expressed as an account value where the concept of benefit reductions for early retirement is not meaningful. The assumed retirement benefit commencement ages for the respective NEOs were as follows:


◦	Ms. Apsey: Age 58


◦	Ms. Holloway Age 58


◦	Mr. Jipping: Age 58


◦	Mr. Oginsky Age 58


◦	Ms. Mason Soneral Age 58

Post-retirement mortality was assumed to be in accordance with the Adjusted RP-2014 table projected for future mortality improvements with MP-2017 generational scale. Benefits under the traditional component of the Qualified Plan were assumed to be paid as a monthly annuity payable for the lifetime of the employee. For all other benefits, payment was assumed to be as a single lump sum, although other actuarially equivalent forms are available.

We maintain one tax-qualified noncontributory defined benefit pension plan and one supplemental nonqualified, noncontributory defined benefit retirement plan. First, we maintain the Qualified Plan, which provides funded, tax-qualified benefits up to the limits on compensation and benefits under the Internal Revenue Code. Generally, all of our salaried employees, including the NEOs, are eligible to participate.

We maintain the ESRP, in which all of our NEOs participate. The ESRP provides additional retirement benefits which are not tax qualified.

The following describes the Qualified Plan and the ESRP, and pension benefits provided to the NEOs under those plans.

Qualified Plan

There are two primary retirement benefit components of the Qualified Plan. Each NEO earns benefits from the Company under only one of these primary components.

Because our first operating utility subsidiary was acquired from DTE Energy, a component of the Qualified Plan bears relation to the DTE Energy Corporation Retirement Plan (the “DTE Plan”). Generally, persons who were participants in the “traditional component” of the DTE Plan as of February 28, 2003 (the date ITCTransmission was acquired from DTE Energy) earn benefits under the traditional component of our Qualified Plan. All other participants earn benefits under the cash balance component. Ms. Apsey also has benefits under the ESRP shift described below.

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

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

Traditional Component of Qualified Plan

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

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

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Benefits provided under the Qualified Plan are based on compensation up to a compensation limit under the Internal Revenue Code (which was $270,000 in 2017, and is indexed in future years). In addition, benefits provided under the Qualified Plan may not exceed a benefit limit under the Internal Revenue Code (which was $215,000 payable as a single life annuity beginning at normal retirement age in 2017).

NEOs may retire with a reduced benefit as early as age 45 after 15 years of credited service. If a NEO has 30 years of credited service at retirement, the benefit that would be payable at normal retirement age is reduced for commencement ages below 58. The percentage of the normal retirement benefit payable at sample commencement ages is as follows:

Age 58 and older: 100%

Age 55: 85%

Age 50: 40%

If a NEO has less than 30 years of credited service at retirement, the benefit that would be payable at normal retirement age is reduced for commencement ages below age 60. The percentage of the normal retirement benefit payable at sample commencement ages is as follows:

Age 60 and older: 100%

Age 55: 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 65, is approximately $106,700. He is fully vested.

Cash Balance Component of Qualified Plan

Mses. Apsey, Holloway and Mason Soneral and Mr. Oginsky participate in the cash balance component of the Qualified Plan. The benefits are stated as a notional account value.

Each year, a NEO’s account is increased by a “contribution credit” equal to 7% of pay. For this purpose, pay is equal to base salary plus bonuses and overtime up to the same compensation limit as applies under the traditional component of the Qualified Plan ($270,000 in 2017). Each year, a NEO’s account is also increased by an “interest credit” based on 30-year Treasury rates.

Upon termination of employment, a vested NEO may elect full payment of his or her account. Alternate forms of benefit (e.g., various forms of annuities) are available as well that have the same actuarial value as the account.

Mses. Apsey, Holloway and Mason Soneral and Mr. Oginsky are entitled to immediate payment of their account value on termination of employment, even if before normal retirement age. Ms. Apsey’s estimated account value as of year-end 2017 is approximately $351,000, Ms. Holloway’s is approximately $213,000, Ms. Mason Soneral’s is approximately $212,000, and Mr. Oginsky’s is approximately $272,000.

ESRP Shift Benefit in Qualified Plan

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

The ESRP shift benefit is an amount that would otherwise be payable from the ESRP, but is instead being paid from the Qualified Plan, subject to applicable qualified plan legal limits on the ability to discriminate in favor of

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

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

Executive Supplemental Retirement Plan

The ESRP is a nonqualified retirement plan. Only selected executives participate, including all our NEOs. The purpose of the ESRP is to promote the success of the Company and its subsidiaries by providing the ability to attract and retain talented executives by providing such designated executives with additional retirement benefits.

The ESRP resembles the cash balance component of the Qualified Plan in that benefits are expressed as a notional account value and the vested account balance is payable as a lump sum on termination of employment, although an installment option of equivalent value is also available.

Each year, a NEO’s account is increased by a “compensation credit” equal to 9% of pay. For this purpose, pay is equal to base salary plus any bonus under the Company’s annual corporate performance bonus plan. There is no limit on compensation that may be taken into account as in the Qualified Plan. Each year, a NEO’s account is also increased by an “investment credit” equal to the same earnings rate as the interest credit in the cash balance component of the Qualified Plan, based on 30-year Treasury rates.

The plan has been in effect since March 1, 2003. Vesting occurs at 20% for each year of participation. All of our NEOs are fully vested. Pursuant to the terms of the plan, Ms. Holloway became fully vested at the time of the Merger.

As noted above in the description of the Qualified Plan, a portion of the ESRP account balance may be shifted to the cash balance component of the Qualified Plan each year, as permitted under the rules for qualified plans. Such a shift allows the NEOs to become immediately vested in the account values shifted, and confers certain tax advantages to the NEOs and us. As of December 31, 2017, the ESRP account values, net of the amounts shifted to the Qualified Plan, are as follows:



Ms. Apsey	$	1,335,751
Ms. Holloway	90,920
Mr. Jipping	1,165,089
Mr. Oginsky	874,474
Ms. Mason Soneral	435,937

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

Nonqualified Deferred Compensation

We maintain the Executive Deferred Compensation Plan under which nonqualified deferred compensation is permissible. Only selected officers of the Company, including the NEOs, are eligible to participate in this plan. NEOs are allowed to defer up to 100% of their salary and bonus. Investment earnings are based on the various investment options available under the plan, and are selected by the individual NEOs. Distributions will generally be made at the NEO’s termination of employment for any reason. Currently none of our NEOs participate in this plan.

Employment Agreements and Potential Payments Upon Termination or Change in Control

Employment Agreements

As referenced above, we entered into employment agreements with Ms. Apsey and Messrs. Jipping and Oginsky in December 2012 which superseded the employment agreements then in effect. In February 2015, we entered into an employment agreement with Ms. Mason Soneral which superseded her employment agreement then in effect. In July 2017, we entered into an employment agreement with Ms. Holloway, which superseded her employment agreement then in effect. Each employment agreement is subject to automatic one-year employment term renewals each year beginning on its second anniversary, unless either party provides the other with 30 days’ advance written notice of intent not to renew the employment term. Ms. Apsey’s agreement was modified in October

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

The employment agreements provide that each NEO will receive an annual base salary equal to their current base salary, which is subject to annual review and increase by our Board of Directors in its discretion. The employment agreements also provide that NEOs are eligible to receive an annual cash bonus, subject to our achievement of certain performance targets established by our Board of Directors, as detailed in “Compensation Discussion and Analysis.” The employment agreements also provide the NEOs with the right to participate in equity plans, employee benefit plans and retirement plans, including but not limited to welfare plans, retiree welfare benefit plans and defined benefit and defined contribution plans.

In addition, the NEOs’ employment agreements provide for payments by us of certain benefits upon termination of employment. The rights available at termination depend on the situation and circumstances surrounding the terminating event. The terms “Cause” and “Good Reason” are used in the employment agreements of each NEO and an understanding of these terms is necessary to determine the appropriate rights for which a NEO is eligible. The terms are defined as follows:

•

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


•	Good reason means: a greater than 10% reduction in the total value of the NEO’s base salary, target bonus, and employee benefits; or if the NEO’s responsibilities and authority are substantially diminished.

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

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


•	any accrued but unpaid compensation and benefits. The benefits include:


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


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


◦	Mr. Oginsky, Ms. Mason Soneral and Ms. Holloway: cash balance under the Qualified Plan and vested portion of ESRP balance


•	continued payment of the NEO’s then-current base salary for two years;

•

if the termination is within six months before or two years after a “Change of Control” (as defined in the employment agreements), payment of an amount equal to two times the average of the annual bonuses, that were payable to the NEO for the three fiscal years immediately preceding the fiscal year in which his or her employment terminates, payable in equal installments over the period in which continued base salary payments are made;


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

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•

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


•	outplacement services for up to two years; and

•

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

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

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

Payments in the Event of Termination

The benefits to be provided to the NEOs as a result of termination under various scenarios are detailed in the tables below. The tables assume that the termination occurred on December 31, 2017.



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	$	—	$	—	$	1,450,000	$	3,149,345	$	—	$	—
Target Short-term Bonus	—		—		—		—		725,000		725,000
Pro Rata Short-term (Annual) Incentive Comp	—		—		1,205,313		1,205,313		—		—
Retention Awards					—		—		—		—
Service-Based Unit Awards (7)	—		—		—		737,690		737,690		737,690
Performance-Based Unit Awards	—		—		—		490,918		1,475,451		1,475,451
Benefits and Perquisites					—
Retirement Plan	—		—		—		—		—		—
ESRP	—		—		—		—		—		—
Perquisites	—		—		25,000		25,000		—		—
Health & Welfare Benefits	—		—		28,809		28,809		—		—
Postretirement Welfare Plan (5)	—		—		594,085		594,085		—		—
Total Payout:	$	—	$	—	$	3,303,207	$	6,231,160	$	2,938,141	$	2,938,141

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Gretchen L. Holloway - Termination Scenarios: Value of Potential Payments
Total Value of Severance, Benefits and Unvested Equity Awards(1)(2)
	Voluntary Resignation		Involuntary For Cause		Involuntary Not-for-Cause or Voluntary Good Reason		Change In Control (pre-tax)(3)		Disability		Death (pre-retirement)(4)
Compensation
Cash Severance	$	—	$	—	$	700,000	$	889,435	$	—	$	—
Target Short-term Bonus	—		—		—		—		350,000		350,000
Pro Rata Short-term (Annual) Incentive Comp	—		—		581,875		581,875		—		—
Service-Based Unit Awards (7)	—		—		—		231,461		231,461		231,461
Performance-Based Unit Awards (8)	—		—		—		154,050		462,997		462,997
280G Cutback	—		—		—		254,204		—		—
Benefits and Perquisites
Retirement Plan	—		—		—		—		—		—
ESRP	—		—		—		—		—		—
Perquisites	—		—		25,000		25,000		—		—
Health & Welfare Benefits	—		—		26,580		26,580		—		—
Total Payout:	$	—	$	—	$	1,333,455	$	2,162,605	$	1,044,458	$	1,044,458



Jon E. Jipping - Termination Scenarios: Value of Potential Payments
Total Value of Severance, Benefits and Unvested Equity Awards(1)(2)
	Voluntary Resignation		Involuntary For Cause		Involuntary Not-for-Cause or Voluntary Good Reason		Change In Control (pre-tax)(3)		Disability		Death (pre-retirement)(4)
Compensation
Cash Severance	$	—	$	—	$	1,070,000	$	2,436,244	$	—	$	—
Target Short-term Bonus	—		—		—		—		535,000		535,000
Pro Rata Short-term (Annual) Incentive Comp	—		—		889,438		889,438		—		—
Service-Based Unit Awards (7)	—		—		—		381,038		381,038		381,038
Performance-Based Unit Awards (8)	—		—		—		253,584		762,146		762,146
Benefits and Perquisites
Retirement Plan (6)	—		—		—		—		—		—
ESRP	—		—		—		—		—		—
Perquisites	—		—		25,000		25,000		—		—
Health & Welfare Benefits	—		—		27,916		27,916		—		—
Total Payout:	$	—	$	—	$	2,012,354	$	4,013,220	$	1,678,184	$	1,678,184

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Daniel J. Oginsky - Termination Scenarios: Value of Potential Payments
Total Value of Severance, Benefits and Unvested Equity Awards(1)(2)
	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	$	—	$	—	$	900,000	$	2,051,238	$	—	$	—
Target Short-term Bonus	—		—		—		—		450,000		450,000
Pro Rata Short-term (Annual) Incentive Comp	—		—		748,125		748,125		—		—
Service-Based Unit Awards (7)	—		—		—		320,532		320,532		320,532
Performance-Based Unit Awards (8)	—		—		—		213,289		641,040		641,040
Benefits and Perquisites
Retirement Plan	—		—		—		—		—		—
ESRP	—		—		—		—		—		—
Perquisites	—		—		25,000		25,000		—		—
Health & Welfare Benefits	—		—		27,022		27,022		—		—
Total Payout:	$	—	$	—	$	1,700,147	$	3,385,206	$	1,411,572	$	1,411,572



Christine Mason Soneral - Termination Scenarios: Value of Potential Payments
Total Value of Severance, Benefits and Unvested Equity Awards(1)(2)
	Voluntary Resignation		Involuntary For Cause		Involuntary Not-for-Cause or Voluntary Good Reason		Change In Control (pre-tax)(3)		Disability		Death (pre-retirement)(4)
Compensation
Cash Severance	$	—	$	—	$	730,000	$	1,296,901	$	—	$	—
Target Short-term Bonus	—		—		—		—		365,000		365,000
Pro Rata Short-term (Annual) Incentive Comp	—		—		606,813		606,813		—		—
Service-Based Unit Awards (7)	—		—		—		259,990		259,990		259,990
Performance-Based Unit Awards (8)	—		—		—		173,007		519,972		519,972
Benefits and Perquisites
Retirement Plan	—		—		—		—		—		—
ESRP	—		—		—		—		—		—
Perquisites	—		—		25,000		25,000		—		—
Health & Welfare Benefits	—		—		27,796		27,796		—		—
Total Payout:	$	—	$	—	$	1,389,609	$	2,389,507	$	1,144,962	$	1,144,962

____________________________

(1)

All scenarios include the value of severance. For Ms. Apsey, the value of the Postretirement Welfare Plan is additionally included where applicable. The Pension Benefits Table assumes that none of the executives are terminated prior to retirement age and that benefits are paid once retirement commences (age 58 is assumed). All other accrued pension benefits, outside of present value reductions outlined in footnote (5), and additional pension benefits upon death, have not been included in these termination scenarios but can be found in the Pension Benefits Table.


(2)	Upon any termination of employment, benefits that are accrued but unpaid prior to that event are paid. These benefits are assumed to be $0 in the above table.


(3)	Change in control values include severance amounts reflecting cutbacks to the extent employer payments exceed the executive respective limits. Ms. Holloway would be subject to an excise tax on the employer payments as of the assumed change in control date; therefore, a cutback in the amount of $254,204 has been reflected.

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(4)

In the event of Mr. Jipping’s termination for death (pre-retirement), his spouse would receive half the 50% joint and survivor annuity under the traditional component of the Qualified Plan, also reduced to reflect a 90% early retirement factor that would apply at age 58 since Mr. Jipping does not have 30 years of service as of December 31, 2017. Under termination for death (pre-retirement), Ms. Apsey’s, Ms. Mason Soneral’s, Ms. Holloway’s, and Mr. Oginsky’s Qualified Plan benefits are payable immediately to the surviving spouse (if any) and ESRP benefits are payable to a designated beneficiary. The above termination scenarios do not reflect the reduction in present value of death benefits ($112,159 for Ms. Apsey, $819,642 for Mr. Jipping, $108,507 for Mr. Oginsky, $58,974 for Ms. Mason Soneral, and $35,520 for Ms. Holloway) compared to present value in the Pension Benefits Table.

(5)

The value of the Postretirement Welfare Plan benefit is included in involuntary termination not for cause and change in control scenarios since Ms. Apsey's employment agreement includes a provision for deemed satisfaction of the eligibility requirements when terminated under these scenarios. It is assumed she would commence her Postretirement Welfare Benefits at age 58. The rate at which future expected benefit payments were discounted in calculating the Postretirement Welfare Plan present values was 3.75%, the same rate used for fiscal year-end 2017 accounting disclosure of the Postretirement Welfare Plan.

(6)

The Pension Benefits Table assumes that Mr. Jipping would not be terminated before retirement age and no early retirement reduction was applied. In all termination scenarios, however, a 90% early retirement factor would apply at age 58 because Mr. Jipping has less than 30 years of service as of December 31, 2017. The above table does not reflect the reduction in the present value ($141,049 except for death) due to applying the 90% early retirement factor.

(7)

Under the 2017 Omnibus Plan, outstanding and unvested service-based units and respective dividend equivalents shall be deemed to be vested service-based units and redeemable on the Change of Control Redemption Date (as defined in the 2017 Omnibus Plan). In the case of Death or Disability (each as defined in the 2017 Omnibus Plan) termination, outstanding and unvested service-based units and respective dividend equivalents shall be deemed to be vested service-based units and redeemable the date of the death or on the date on which the grantee’s service is terminated due to Disability. In the case of Retirement or Involuntary Termination Without Cause (each as defined in the 2017 Omnibus Plan) within one year of the grant date, outstanding and unvested service-based units and respective dividend equivalents shall be deemed to be forfeited. If Retirement or Involuntary Termination Without Cause occurs one year or more after the grant date, service-based units and respective dividend equivalents shall be deemed to have vested pro-rata based on the period served from the grant date to termination.

(8)

Under the 2017 Omnibus Plan, outstanding and unvested performance-based unit awards and respective dividend equivalents accelerate on a prorated basis under a Change in Control (as defined in the 2017 Omnibus Plan), based on the higher of (A) 100% of the target number of performance-based units in the award or (B) the actual payout percentage based on the Committee’s assessment of performance of the payment criteria from the beginning of the Payment Criteria Period for the award through the date of the Change of Control (as defined in the 2017 Omnibus Plan). In the case of Death or Disability termination, the outstanding and unvested performance-based unit awards and respective dividend equivalents will remain outstanding and be payable on the payout date of such awards subject to the achievement of the applicable payment criteria. Values shown in the tables above are based on target performance as an estimate of potential payments. In the case of Retirement or Involuntary Termination Without Cause within one year of the award grant date, outstanding and unvested performance-based unit awards and respective dividend equivalents shall be deemed to be forfeited. If Retirement or Involuntary Termination Without Cause occurs one year or more after the grant date, performance-based unit awards and respective dividend equivalents shall be deemed to have vested pro-rata based on the period served from grant date to termination.

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

Pay Ratio

As required by the U.S. Congress under the Dodd-Frank Wall Street Reform and Consumer Protection Act, and the SEC under Item 402(u) of Regulation S-K, we are providing the following information about the relationship of the annual total compensation of our employees and the annual total compensation of Linda H. Apsey our CEO:

For 2017, our last completed fiscal year:

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the median of the annual total compensation of all employees of the Company (other than Ms. Apsey), was $142,593; and

the annual total compensation of Ms. Apsey as reported in the Summary Compensation Table was $4,626,345.

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

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

Using our “median employee” and Ms. Apsey, we calculated the 2017 Summary Compensation Table values for each according to SEC rules.

Director Compensation

The following table provides information concerning the compensation of each person who served as a non-employee director of the Company during 2017.

Non-Employee Director Compensation Table



Name (1)	Fees Earned or Paid in Cash ($) (2)		Stock Awards ($)		Total ($)
(a)	(b)		(c)		(h)
Robert A. Elliott	$	125,000	$	—	$	125,000
Albert Ernst	125,000		—		125,000
Rhys D. Evenden (3)	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	24,457		—		24,457
Thomas G. Stephens	132,500		—		132,500
Joseph L. Welch	150,000		—		150,000

____________________________


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


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


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

Directors who are employees of the Company do not receive separate compensation for their services as a director. All non-employee directors are compensated under our non-employee director compensation policy, pursuant to which they are paid an annual cash retainer of $125,000. In addition, we pay an additional cash retainer of $7,500 annually to the chair of each Board committee and $25,000 annually to our chairman. We do not pay per-meeting fees under the policy. Beginning in calendar year 2017, non-employee directors were and will continue to be reimbursed for their out-of-pocket expenses.

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

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permissible. Only non-employee directors of the Company are eligible to participate in this plan. Directors are allowed to defer up to 100% of their annual board compensation. Investment earnings are based on the various investment options available under the plan, and are selected by the individual directors. Distributions will be made when the director ceases to serve on the Board and/or ceases to provide other non-employee consulting services to the Company or any Fortis entity.


ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.

The following table sets forth certain information regarding the ownership of our common stock and Fortis’ common stock as of February 1, 2018, except as otherwise indicated, by:


•	each of our current directors;


•	each of the persons named in the Summary Compensation Table under Item 11; and


•	all current directors and executive officers as a group.

The number of shares beneficially owned is determined under rules of the SEC and the information is not necessarily indicative of beneficial ownership for any other purpose. Under such rules, beneficial ownership includes any shares as to which the individual has sole or shared voting power or investment power and also any shares which the individual has the right to acquire on February 1, 2018 or within 60 days thereafter through the exercise of any stock option or other right. Unless otherwise indicated, each holder has sole investment and voting power with respect to the shares set forth in the following table:



Name of Beneficial Owner	Number of Shares Beneficially Owned	Percent of Class		Fortis Inc. Number of shares Beneficially Owned	Percent of Class
Linda H. Apsey	—	—	%	53,889	*
Gretchen L. Holloway	—	—	%	4,194	*
Jon E. Jipping	—	—	%	120,000	*
Daniel J. Oginsky	—	—	%	72,621	*
Christine Mason Soneral	—	—	%	—	—
Robert A. Elliott	—	—%		—	—
Albert Ernst	—	—	%	13,073 (2)	*
Rhys D. Evenden	—	—	%	—	—
James P. Laurito	—	—	%	1,965	—
Barry V. Perry	—	—	%	787,975 (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)	—	—	%	2,234,143	*

* Less than one percent

____________________________


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


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


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

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

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

At December 31, 2017, there were no securities authorized for issuance under any compensation plans of ITC Holdings Corp.

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

CERTAIN TRANSACTIONS

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

Although the Company does not have a written policy with regard to the approval of transactions between the Company and its executive officers and directors, each director and officer must annually submit a form to the General Counsel disclosing his or her conflicts or potential conflicts of interest or certifying that no such conflicts of interest exist. Throughout the year, if any transaction constituting a conflict of interest arises or circumstances otherwise change that would cause a director’s or officer’s annual conflict certification to become incorrect, the director or officer must inform the General Counsel of such circumstances. The Governance and Human Resources Committee reviews existing conflicts as well as potential conflicts of interest and determines whether any further action is necessary, such as recommending to the Board whether a director or officer should be requested to offer his or her resignation. Where the Board makes a determination regarding a potential conflict of interest, a majority of the Board (excluding any interested member or members) shall decide upon an appropriate course of action. Additionally, any director or officer who has a question about whether a conflict exists must bring it to the attention of the Company’s General Counsel or Chairperson of the Governance and Human Resources Committee.

Clayton Welch, Jennifer Welch, Jessica Uher and Katie Welch (each of whom is a son, daughter or daughter-in-law of Joseph L. Welch, the Company’s Chairman) were employed by us as a Senior Engineer, Fleet Manager, Manager of Corporate and Field Facilities, and Senior Accountant, respectively, during 2017 and continue to be employed by us. These individuals are employed on an “at will” basis and compensated on the same basis as our other employees of similar function, seniority and responsibility without regard to their relationship with Mr. Welch. These four individuals, none of whom resides with or is supported financially by Mr. Welch, received aggregate salary, bonus, long-term incentives and taxable perquisites for services rendered in the above capacities totaling $507,889 during 2017.

DIRECTOR INDEPENDENCE

Based on the absence of any material relationship between them and us, other than their capacities as directors, the Board has determined that Ms. Pierce and Messrs. Elliott, Ernst, Prust, Rothwell and Stephens are “independent” as defined in the Shareholders Agreement. In addition, our Board has determined that, as the committees are currently constituted, a majority of the members of the Audit and Risk Committee are “independent” as defined in the Shareholders Agreement. None of the directors determined to be independent is or ever has been employed by us. The Company has made charitable contributions of less than $1 million each to organizations with which certain of our directors have affiliations. The Board determined that these contributions would not interfere with the exercise of independent judgment by these directors in carrying out their responsibilities.

An independent director under the Shareholders Agreement is a director who meets all of the following requirements: (a) is elected by the shareholders of Investment Holdings; (b) is designated as an independent director by the Investment Holdings’ board and Company Board, or the shareholders of Investment Holdings; (c) is not a director that is nominated by Finn Investment Pte Ltd or any successor or permitted assign thereof and appointed as a member of the Investment Holdings’ board and Company Board in accordance with the Shareholders Agreement; (d) is not and during the three years prior to being designated as an independent director has not been any of the following: (i) a director of FortisUS or any of its affiliates (other than Investment Holdings or the Company); or (ii) an officer or employee of Investment Holdings, the Company, FortisUS or any of their affiliates; and (e) would meet the definition of “independent director” under the New York Stock Exchange Listed Company Manual if such director were a member of the board of directors of Fortis, FortisUS, Investment Holdings, or the Company

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

Mr. Elliott serves on the board of directors of UNS Energy Corporation, a wholly-owned subsidiary of FortisUS. When determining Mr. Elliott’s independence, the board and shareholders agreed to waive the requirements set forth in the definition of independent director under the Shareholders Agreement which states that a director is not and during the three years prior to being designated as a director of the company has not served as a director of FortisUS or any of its affiliates.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.

The following table provides a summary of the aggregate fees incurred for Deloitte’s services in 2017 and 2016:



	2017		2016
Audit fees (1)	$	1,888,000	$	1,866,000
Audit-related fees (2)	329,000		924,000
Tax fees (3)	187,000		753,000
All other fees (4)	127,000		10,000
Total fees	$	2,531,000	$	3,553,000

____________________________


(1)	Audit fees were for professional services rendered for the audit of our consolidated financial statements and internal controls and reviews of the interim consolidated financial statements included in quarterly reports and services that are normally provided by Deloitte in connection with statutory and regulatory filing engagements.

(2)

Audit-related fees were for assurance and related services that are reasonably related to the performance of the audit or review of our consolidated financial statements and are not reported under “Audit Fees.” These services include due diligence support relating to merger and acquisition activity and the audit of our employee benefit plans and accounting consultations. The fees also include amounts for the services provided in connection with our securities offerings and accounting consultations and audits in connection with acquisitions.


(3)	Tax fees were professional services for federal and state tax compliance, tax advice and tax planning, including services to support merger and acquisition activity.


(4)	All other fees were for services other than the services reported above. These services included subscriptions to the Deloitte Accounting Research Tool, attendance at the Deloitte Power and Utilities Seminar and Utility Accounting Workshop, and assessment of our ERM Program.

The Audit and Risk Committee of the Board of Directors does not consider the provision of the services described above by Deloitte to be incompatible with the maintenance of Deloitte’s independence.

The Audit and Risk Committee has adopted a pre-approval policy for all audit and non-audit services pursuant to which it pre-approves all audit and non-audit services provided by the independent registered public accounting firm prior to the engagement with respect to such services. To the extent that we need an engagement for audit and/or non-audit services between Audit and Risk Committee meetings, the Audit and Risk Committee chairman is authorized by the Audit and Risk Committee to approve the required engagement on its behalf.

The Audit and Risk Committee approved all of the services performed by Deloitte in 2017.

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.



(a)	(1)	Financial Statements:
		Management’s Report on Internal Control over Financial Reporting
		Report of Independent Registered Public Accounting Firm
		Consolidated Statements of Financial Position as of December 31, 2017 and 2016
		Consolidated Statements of Operations for the Years Ended December 31, 2017, 2016 and 2015
		Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2017, 2016 and 2015
		Consolidated Statements of Changes in Stockholder's Equity for the Years Ended December 31, 2017, 2016 and 2015
		Consolidated Statements of Cash Flows for the Years Ended December 31, 2017, 2016 and 2015
		Notes to Consolidated Financial Statements
	(2)	Financial Statement Schedules
		Schedule I — Condensed Financial Information of Registrant
		All other schedules for which provision is made in Regulation S-X either (i) are not required under the related instructions or are inapplicable and, therefore, have been omitted, or (ii) the information required is included in the consolidated financial statements or the notes thereto that are a part hereof.
(b)		Exhibit Listing

The following exhibits are filed as part of this report or filed previously and incorporated by reference to the filing indicated. Our SEC file number is 001-32576.



Exhibit No.			Description of Exhibit

2.1			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)

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Exhibit No.		Description of Exhibit



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)

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)

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

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)

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Exhibit No.		Description of Exhibit



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)

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)

*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)

*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)

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Exhibit No.		Description of Exhibit



*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)

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

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

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

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

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

*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)

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

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

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

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

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Exhibit No.		Description of Exhibit



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

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

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

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

*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)

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

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

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

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)

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Exhibit No.		Description of Exhibit



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)

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)

12.1			Ratio of Earnings to Fixed Charges for ITC Holdings Corp.

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)	2017		2016
ASSETS
Current assets
Cash and cash equivalents	$	60	$	4
Accounts receivable from subsidiaries	21		16
Income tax receivable	15		17
Prepaid and other current assets	3		8
Total current assets	99		45
Other assets
Investment in subsidiaries	4,461		4,171
Deferred income taxes	141		208
Other	96		78
Total other assets	4,698		4,457
TOTAL ASSETS	$	4,797	$	4,502
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities
Intercompany tax payable to subsidiaries	$	—	$	85
Accrued compensation	28		14
Accrued interest	33		33
Debt maturing within one year	—		195
Other	8		13
Total current liabilities	69		340
Accrued pension and postretirement liabilities	74		68
Other	6		1
Long-term debt (net of deferred financing fees and discount of $22 and $16, respectively)	2,728		2,192
STOCKHOLDER’S EQUITY
Common stock, without par value, 235,000,000 shares authorized as of December 31, 2017, and 224,203,112 shares issued and outstanding at December 31, 2017 and 2016	892		892
Retained earnings	1,026		1,007
Accumulated other comprehensive income	2		2
Total stockholder’s equity	1,920		1,901
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	4,797	$	4,502

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 OPERATIONS (PARENT COMPANY ONLY)



	Year Ended December 31,
(In millions)	2017			2016			2015
Other income	$	2		$	1		$	1
General and administrative expense	(11		)	(122		)	(6		)
Taxes other than income taxes	(2		)	—			—
Interest expense	(120		)	(113		)	(106		)
LOSS BEFORE INCOME TAXES	(131		)	(234		)	(111		)
INCOME TAX BENEFIT	(6		)	(122		)	(45		)
LOSS AFTER TAXES	(125		)	(112		)	(66		)
EQUITY IN SUBSIDIARIES’ NET EARNINGS	444			358			308
NET INCOME	$	319		$	246		$	242

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)	2017		2016			2015
NET INCOME	$	319	$	246		$	242
OTHER COMPREHENSIVE LOSS
Derivative instruments (net of tax of $3 and $1 for the years ended December 31, 2016 and 2015, respectively)	—		(2		)	(1		)
TOTAL OTHER COMPREHENSIVE LOSS, NET OF TAX	—		(2		)	(1		)
TOTAL COMPREHENSIVE INCOME	$	319	$	244		$	241

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)	2017			2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	319		$	246		$	242
Adjustments to reconcile net income to net cash (used in) provided by operating activities:
Equity in subsidiaries' earnings	(444		)	(358		)	(308		)
Dividends from subsidiaries	3			10			185
Deferred and other income taxes	67			(69		)	(116		)
Net intercompany tax payments (to) from subsidiaries	(13		)	(72		)	121
Expense for the accelerated vesting of share-based awards associated with the Merger	—			41			—
Other	5			25			21
Changes in assets and liabilities, exclusive of changes shown separately:
Accounts receivable from subsidiaries	(4		)	22			3
Income tax receivable	2			(17		)	—
Prepaid and other current assets	(2		)	1			—
Intercompany tax payable to subsidiaries	(72		)	85			—
Accrued Compensation	14			(10		)	1
Accrued taxes	—			(35		)	9
Other current liabilities	(5		)	3			3
Other non-current assets and liabilities, net	8			5			(5		)
Net cash (used in) provided by operating activities	(122		)	(123		)	156
CASH FLOWS FROM INVESTING ACTIVITIES
Equity contributions to subsidiaries	(148		)	(87		)	(263		)
Return of capital from subsidiaries	296			274			161
Other	(9		)	(9		)	(11		)
Net cash provided by (used in) investing activities	139			178			(113		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt, net of discount	999			399			—
Borrowings under revolving credit agreement	97			126			839
Borrowings under term loan credit agreement	200			—			—
Net issuance of commercial paper, net of discount	(148		)	48			95
Retirement of long-term debt — including extinguishment of debt costs	(437		)	(139		)	—
Repayments of revolving credit agreement	(170		)	(191		)	(755		)
Repayments of term loan credit agreements	(200		)	(161		)	—
Dividends on common stock	—			(90		)	(108		)
Dividends to ITC Investment Holdings Inc.	(300		)	(33		)	—
Issuance of common stock	—			13			14
Repurchase and retirement of common stock	—			(9		)	(137		)
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	(2		)	(22		)	11
Net cash provided by (used in) financing activities	39			(59		)	(41		)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	56			(4		)	2
CASH AND CASH EQUIVALENTS — Beginning of period	4			8			6
CASH AND CASH EQUIVALENTS — End of period	$	60		$	4		$	8

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, 2017 for dividends based on management's intent to maintain the FERC-approved capital structure targeting 60% equity and 40% debt for each of our Regulated Operating Subsidiaries. These net assets are included in Schedule I as the line-item “Investments in subsidiaries.” Each of our subsidiaries, however, is legally distinct from us and has no obligation, contingent or otherwise, to make funds available to us.

Supplementary Cash Flows Information



	Year Ended December 31,
(In millions)	2017			2016		2015
Supplementary cash flows information:
Interest paid	$	115		$	112	$	104
Income taxes paid (a)	—			23		56
Supplementary non-cash investing and financing activities:
Equity transfers to (from) subsidiaries	(2		)	—		1

____________________________


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

2. DEBT

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



(In millions)
2018	$	—
2019	—
2020	200
2021	—
2022	500
2023 and thereafter	2,050
Total	$	2,750

Refer to Note 9 to the consolidated financial statements for a description of the ITC Holdings Senior Notes, the ITC Holdings Revolving Credit Agreements, the ITC Holdings Commercial Paper Program and related items.

Based on the borrowing rates obtained from third party lending institutions currently available for bank loans with similar terms and average maturities from active markets, the fair value of the ITC Holdings Senior Notes was $2,908 million and $2,297 million at December 31, 2017 and 2016, respectively. The total book value of the ITC

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Holdings Senior Notes, net of discount and deferred financing fees, was $2,728 million and $2,169 million at December 31, 2017 and 2016, respectively. At December 31, 2017 we did not have anything outstanding under our revolving and term loan credit agreements, which are variable rate loans compared to $73 million as of December 31, 2016. The fair value of these loans approximates book value based on the borrowing rates currently available for variable rate loans obtained from third party lending institutions. These fair values represent Level 2 under the three-tier hierarchy described in Note 12 to the consolidated financial statements. At December 31, 2017 ITC Holdings did not have any commercial paper issued and outstanding under the commercial paper program compared to $145 million as of December 31, 2016. Due to the short-term nature of these financial instruments, the carrying value approximates fair value.

Covenants

Our debt instruments contain numerous financial and operating covenants that place significant restrictions on certain transactions, such as incurring additional indebtedness, engaging in sale and lease-back transactions, creating liens or other encumbrances, entering into mergers, consolidations, liquidations or dissolutions, creating or acquiring subsidiaries, selling or otherwise disposing of all or substantially all of our assets and paying dividends. In addition, the covenants require us to meet certain financial ratios, such as maintaining certain net debt to capitalization ratios and certain funds from operations to net debt levels. At December 31, 2017, we were not in violation of any debt covenant.

3. RELATED-PARTY TRANSACTIONS

Our related-party transactions during 2017, 2016 and 2015 were as follows:



	Year Ended December 31,
(In millions)	2017			2016			2015
Equity contributions to subsidiaries	$	148		$	87		$	263
Dividends from subsidiaries (a)	3			10			185
Return of capital from subsidiaries (a)	296			274			161

Net income tax payments (to) from: (b)
ITCTransmission	$	4		$	(28	)	$	36
METC	1			(14		)	39
ITC Midwest	5			(34		)	31
ITC Great Plains	11			4			15
ITC Interconnection	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.

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Intercompany Tax Sharing Arrangement

As discussed in Note 1 to the condensed financial statements of the parent company, we are a holding company with no business operations. We file consolidated income tax returns that include our affiliates, which are taxed as a corporation for federal and Michigan income tax purposes. We operate under an intercompany tax sharing arrangement with our subsidiaries and as a result may receive or pay federal and state income tax based on their stand-alone company tax positions.

Retirement Benefits

We are the plan sponsor for a pension plan, other postretirement plans and a defined contribution plan. The benefits-related expenses recorded by our affiliates result from the inclusion of benefit costs as a component of the total charge for services performed by our employees under the cost assignment and allocation methods used by us and our subsidiaries.

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ITEM 16. FORM 10-K SUMMARY.

Not applicable.

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, 2018.



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, 2018
Linda H. Apsey	Officer (principal executive officer)

/s/ GRETCHEN L. HOLLOWAY	Senior Vice President and Chief Financial Officer	February 14, 2018
Gretchen L. Holloway	(principal financial and accounting officer)

/s/ JOSEPH L. WELCH	Director and Chairman	February 14, 2018
Joseph L. Welch

/s/ ROBERT A. ELLIOTT	Director	February 14, 2018
Robert A. Elliott

/s/ ALBERT ERNST	Director	February 14, 2018
Albert Ernst

/s/ RHYS D. EVENDEN	Director	February 14, 2018
Rhys D. Evenden

/s/ JAMES P. LAURITO	Director	February 14, 2018
James P. Laurito

/s/ BARRY V. PERRY	Director	February 14, 2018
Barry V. Perry

/s/ SANDRA E. PIERCE	Director	February 14, 2018
Sandra E. Pierce

/s/ KEVIN L. PRUST	Director	February 14, 2018
Kevin L. Prust

/s/ A. DOUGLAS ROTHWELL	Director	February 14, 2018
A. Douglas Rothwell

/s/ THOMAS G. STEPHENS	Director	February 14, 2018
Thomas G. Stephens

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	One-Percentage-		One-Percentage-
(In millions)	Point Increase		Point Decrease
Effect on total of service and interest cost	$	3	$	(2	)
Effect on postretirement benefit obligation	21		(15		)



	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	$	—	$	—


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


(b)	Includes unrealized gains and losses on available-for-sale securities, net of tax, of less than $1 million for the years ended December 31, 2017, 2016 and 2015.



(In millions)	2017 (a)		2016		2015
Operation and maintenance expenses	$	1	$	2	$	2
General and administrative expenses (b)	3		52		11
Amounts capitalized to property, plant and equipment	1		5		5
Total share-based compensation	$	5	$	59	$	18
Total tax benefit recognized in the consolidated statements of operations	$	1	$	49	$	5


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



	Number of
	Performance
	Based Units
PBUs at December 31, 2016	—
Granted	344,900
Vested	—
Forfeited	(10,514	)
PBUs at December 31, 2017	334,386



	Number of
	Service
	Based Units
SBUs at December 31, 2016	—
Granted	267,118
Vested	(457	)
Forfeited	(8,892	)
SBUs at December 31, 2017	257,769



	Net Investments (a)
(In millions)	Substations		Lines		Other
ITCTransmission (b)	$	—	$	29	$	—
METC (c)	14		41		—
ITC Midwest (d)	27		36		7
ITC Great Plains (e)	10		23		—
Total	$	51	$	129	$	7


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


(d)	ITC Midwest has joint sharing of several substations and transmission lines with various parties. As of December 31, 2017, ITC Midwest had net investments in jointly owned substation assets under construction of $7 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, 2017.



	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


(a)	Reconciliation of total assets results primarily from differences in the netting of deferred tax assets and liabilities at our Regulated Operating Subsidiaries 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.



	First		Second		Third		Fourth
(In millions)	Quarter		Quarter		Quarter		Quarter		Year
2017
Operating revenues (a)	$	298	$	303	$	299	$	311	$	1,211
Operating income (a)	173		176		175		184		708
Net income (a)	80		81		82		76		319
2016
Operating revenues (a)	$	280	$	298	$	254	$	293	$	1,125
Operating income (a)	147		161		125		89		522
Net income (a)	65		74		51		56		246



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


•	Long-term equity incentives. We granted long-term equity incentive awards to our NEOs in March 2017. Total award opportunities were set as a percentage of base salary and delivered one-third in the form of service-based units and two-thirds in the form of performance-based units.


•	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.


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