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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(Mark One)
☑
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the fiscal year ended
December 31, 2019
OR
☐
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number: 001-32576
ITC HOLDINGS CORP.
(Exact Name of Registrant as Specified in Its Charter)
Michigan
 
32-0058047
(State or Other Jurisdiction of Incorporation or Organization)
 
(I.R.S. Employer Identification No.)
27175 Energy Way
Novi, Michigan 48377
(Address Of Principal Executive Offices, Including Zip Code)
(248) 946-3000
(Registrant’s Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
Trading Symbol(s)
Name of Each Exchange on Which Registered
None
None
None
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes 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 Act. 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 every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer
 
Accelerated filer
 
Non-accelerated filer
 
Smaller Reporting Company
 
Emerging growth company 
o
 
o
 
☑
 
☐
 
☐
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 ☐ No þ
The aggregate market value of the registrant’s common stock held by non-affiliates on June 30, 2019 was $0.
All shares of outstanding common stock of ITC Holdings Corp. are held by its parent company, ITC Investment Holdings Inc., which is an indirect subsidiary of Fortis Inc. There were 224,203,112 shares of common stock, no par value, outstanding as of February 12, 2020.
DOCUMENTS INCORPORATED BY REFERENCE
None
 


ITC Holdings Corp.
Form 10-K for the Fiscal Year Ended December 31, 2019
INDEX

 
 
Page
7
7
14
20
20
21
21
 
 
 
21
21
22
23
40
42
88
88
88
 
 
 
88
88
92
120
121
122
 
 
 
123
123
134
135



2

Unless otherwise noted or the context requires, all references in this report to:
ITC Holdings Corp. and its subsidiaries
•
“ITC Great Plains” are references to ITC Great Plains, LLC, a wholly-owned subsidiary of ITC Holdings;
•
“ITC Holdings” are references to ITC Holdings Corp. and not any of its subsidiaries;
•
“ITC Interconnection” are references to ITC Interconnection LLC, a wholly-owned subsidiary of ITC Holdings;
•
“ITC Midwest” are references to ITC Midwest LLC, a wholly-owned subsidiary of ITC Holdings;
•
“ITCTransmission” are references to International Transmission Company, a wholly-owned subsidiary of ITC Holdings;
•
“METC” are references to Michigan Electric Transmission Company, LLC, a wholly-owned subsidiary of MTH;
•
“MISO Regulated Operating Subsidiaries” are references to ITCTransmission, METC and ITC Midwest together;
•
“MTH” are references to Michigan Transco Holdings, LLC, the sole member of METC and a wholly-owned subsidiary of ITC Holdings;
•
“Regulated Operating Subsidiaries” are references to ITCTransmission, METC, ITC Midwest, ITC Great Plains and ITC Interconnection together; and
•
“Company”, “we,” “our” and “us” are references to ITC Holdings together with all of its subsidiaries.
Other definitions
•
“2017 Omnibus Plan” are references to the Company’s February 27, 2017 long-term equity incentive plan as amended July 10, 2017 and February 4, 2020;
•
“Executive Omnibus Plan” are references to the Company’s February 4, 2020 long-term equity incentive plan;
•
“ACPB” are references to an award under the annual corporate performance bonus plan;
•
“ADIT” are references to accumulated deferred income tax;
•
“AFUDC” are references to an allowance for funds used during construction;
•
“ALJ” are references to an administrative law judge;
•
“Ancillary Services Agreement” are references to the Amended and Restated Purchase and Sale Agreement for Ancillary Services entered into by METC and Consumers Energy dated as of April 29, 2002;
•
“AOCI” are references to accumulated other comprehensive income or (loss);
•
“ARAM” are references to the average rate assumption method of amortization;
•
“CIA” are references to the Coordination and Interconnection Agreement entered into by ITCTransmission and DTE Electric dated as of February 28, 2003;
•
“Consumers Energy” are references to Consumers Energy Company, a wholly-owned subsidiary of CMS Energy Corporation;
•
“D.C. Circuit Court” are references to the U.S. Court of Appeals for the District of Columbia Circuit;
•
“DCF” are references to discounted cash flow;
•
“DOE” are references to the Department of Energy;
•
“DTE Electric” are references to DTE Electric Company, a wholly-owned subsidiary of DTE Energy;
•
“DTE Energy” are references to DTE Energy Company;


3

•
“DTIA” are references to the Distribution-Transmission Interconnection Agreement entered into by ITC Midwest and IP&L dated as of December 17, 2007 and amended and restated effective as of December 1, 2016;
•
“DT Interconnection Agreement” are references to the Amended and Restated Distribution-Transmission Interconnection Agreement entered into by METC and Consumers Energy dated April 1, 2001 and most recently amended and restated effective as of January 1, 2015;
•
“Easement Agreement” are references to the Amended and Restated Easement Agreement entered into by METC and Consumers Energy dated April 29, 2002 and as further supplemented;
•
“Eiffel” are references to Eiffel Investment Pte Ltd, a private limited company duly organized and validly existing under the laws of Singapore that is the GIC subsidiary that is a minority investor in ITC Investment Holdings and successor to Finn Investment Pte Ltd;
•
“ESPP” are references to the Fortis Amended and Restated 2012 Employee Share Purchase Plan;
•
“Exchange Act” are references to the Securities Exchange Act of 1934, as amended;
•
“FASB” are references to the Financial Accounting Standards Board;
•
“FERC” are references to the Federal Energy Regulatory Commission;
•
“Fortis” are references to Fortis Inc.;
•
“FortisUS” are references to FortisUS Inc., an indirect subsidiary of Fortis;
•
“Formula Rate” are references to a FERC-approved formula template used to calculate an annual revenue requirement;
•
“FPA” are references to the Federal Power Act;
•
“GAAP” are references to accounting principles generally accepted in the United States of America;
•
“Generator Interconnection Agreement” are references to the Amended and Restated Generator Interconnection Agreement entered into by Consumers Energy and METC dated as of April 29, 2002 and most recently amended effective as of November 1, 2018;
•
“GIC” are references to GIC Private Limited;
•
“GIAs” are references to generator interconnection agreements;
•
“GIOA” are references to the Generator Interconnection and Operation Agreement entered into by DTE Electric and ITCTransmission dated as of February 28, 2003;
•
“Initial Complaint” are references to a November 2013 complaint to the FERC under Section 206 of the FPA regarding the base ROE;
•
“ITC Investment Holdings” are references to ITC Investment Holdings Inc., a majority owned indirect subsidiary of Fortis in which GIC has an indirect minority ownership interest;
•
“IP&L” are references to Interstate Power and Light Company, an Alliant Energy Corporation subsidiary;
•
“IRS” are references to the Internal Revenue Service;
•
“ISO” are references to Independent System Operators;
•
“KCC” are references to the Kansas Corporation Commission;
•
“kV” are references to kilovolts (one kilovolt equaling 1,000 volts);
•
“kW” are references to kilowatts (one kilowatt equaling 1,000 watts);
•
“LBA” are references to a Local Balancing Authority;
•
“LGIA” are references to the Large Generator Interconnection Agreement entered into by ITC Midwest, IP&L, and MISO dated as of December 20, 2007 and amended as of August 2, 2017;
•
“LIBOR” are references to the London Interbank Offered Rate;
•
“MECS” are references to the Michigan Electric Coordinated Systems;


4

•
“Merger Agreement” are references to the agreement and plan of merger between Fortis, FortisUS, Element Acquisition Sub, Inc. and ITC Holdings for the merger;
•
“Mid-Kansas” are references to Mid-Kansas Electric Company LLC;
•
“Mid-Kansas Agreement” are references to an Amended and Restated Maintenance Agreement entered into by Mid-Kansas and ITC Great Plains dated as of August 24, 2010, and most recently amended effective as of March 6, 2017;
•
“MISO” are references to the Midcontinent Independent System Operator, Inc., a FERC-approved RTO which oversees the operation of the bulk power transmission system for a substantial portion of the Midwestern United States and Manitoba, Canada, and of which ITCTransmission, METC and ITC Midwest are members;
•
“MISO ROE Complaints” are references to the Initial Complaint and the Second Complaint;
•
“MOA” are references to the Master Operating Agreement entered into by ITCTransmission and DTE Electric dated as of February 28, 2003;
•
“Moody’s” are references Moody’s Investor Service, Inc.;
•
“MVPs” are references to multi-value projects, which have been determined by MISO to have regional value while meeting near-term system needs;
•
“MW” are references to megawatts (one megawatt equaling 1,000,000 watts);
•
“NERC” are references to the North American Electric Reliability Corporation;
•
“NOLs” are references to net operating loss carryforwards for income taxes;
•
“November 2018 Order” are references to an order issued by the FERC on November 15, 2018 regarding MISO ROE Complaints;
•
“November 2019 Order” are references to an order issued by the FERC on November 21, 2019 regarding MISO ROE Complaints;
•
“NYSE” are references to the New York Stock Exchange;
•
“Operating Agreement” are references to the Amended and Restated Operating Agreement entered into by Consumers Energy and METC dated as of April 29, 2002;
•
“OSA” are references to the Operations Services Agreement for 34.5 kV Transmission Facilities entered into by ITC Midwest and IP&L effective as of January 1, 2011;
•
“PBU” are references to a performance-based unit;
•
“PCBs” are references to polychlorinated biphenyls;
•
“PJM” are references to PJM Interconnection LLC, a FERC-approved RTO which oversees the operation of the bulk power transmission system for a substantial portion of the Eastern United States, and of which ITC Interconnection is a member;
•
“ROE” are references to return on equity;
•
“RSGM” are references to the Reverse South Georgia Method of amortization;
•
“RTO” are references to Regional Transmission Organizations;
•
“SBU” are references to a service-based unit;
•
“SEC” are references to the Securities and Exchange Commission;
•
“Second Complaint” are references to an additional complaint filed on February 12, 2015 with the FERC under Section 206 of the FPA regarding the base ROE;
•
“September 2016 Order” are references to an order issued by the FERC on September 28, 2016 regarding the Initial Complaint;
•
“Shareholders Agreement” are references to the Shareholders’ Agreement, dated as of October 14, 2016 by and among the Company, ITC Investment Holdings, FortisUS, Eiffel (as successor to Finn Investment


5

Pte Ltd), and any other person that becomes a shareholder of ITC Investment Holdings pursuant to such agreement;
•
“SPP” are references to Southwest Power Pool, Inc., a FERC-approved RTO which oversees the operation of the bulk power transmission system for a substantial portion of the South Central United States, and of which ITC Great Plains is a member;
•
“S&P” are references to S&P Global Ratings;
•
“TCJA” are references to the Tax Cuts and Jobs Act of 2017, a comprehensive tax reform bill enacted on December 22, 2017;
•
“TO” are references to transmission owner; and
•
“ULCS” are references to Utility Lines Construction Services, LLC


6

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. In 2016, ITC Holdings became a wholly-owned subsidiary of ITC Investment Holdings. Fortis owns a majority indirect equity interest in ITC Investment Holdings, with GIC holding an indirect equity interest of 19.9%. Through our Regulated Operating Subsidiaries, we own and operate high-voltage electric transmission systems in Michigan’s Lower Peninsula and portions of Iowa, Minnesota, Illinois, Missouri, Kansas and Oklahoma that transmit electricity from generating stations to local distribution facilities connected to our transmission systems. Our business strategy is to own, operate, maintain and invest in transmission infrastructure in order to enhance system integrity and reliability, reduce transmission constraints and support new generating resources to interconnect to our transmission systems.
As electric transmission utilities with rates regulated by the FERC, our Regulated Operating Subsidiaries earn revenues for the use of their electric transmission systems by our customers, which include investor-owned utilities, municipalities, cooperatives, power marketers and alternative energy suppliers. As independent transmission companies, our Regulated Operating Subsidiaries are subject to rate regulation only by the FERC, and our cost-based rates are discussed in “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cost-Based Formula Rates with True-Up Mechanism.”
Development of Business
We are actively identifying and investing in transmission infrastructure required to meet reliability needs and energy policy objectives. Our long-term growth plan includes ongoing investments in our current regulated transmission systems and the identification of incremental development projects throughout North America. Refer to “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Investment and Operating Results Trends” for additional details about our long-term capital investments. Refer to the discussion of risks associated with our strategic development opportunities in “Item 1A Risk Factors.”
We expect to invest approximately $3.7 billion from 2020 through 2024 at our Regulated Operating Subsidiaries. Included in this amount are capital expenditures to: (1) maintain and replace our current transmission infrastructure; (2) enhance system integrity and reliability and accommodate load growth; (3) upgrade physical and technological grid security and (4) develop and build regional transmission infrastructure, including additional transmission facilities that will provide interconnection opportunities for generating facilities.
Through our development activities, we pursue projects in North America that are in line with our business strategy, enhance competitive wholesale electricity markets and facilitate interconnections of new generating resources, including wind generation and other renewable resources necessary to achieve state and federal policy goals. We are also actively pursuing development initiatives related to grid modernization and contracted transmission projects.
Operations
As transmission-only companies, our Regulated Operating Subsidiaries function as conduits, allowing for power from generators to be transmitted to local distribution systems either entirely through our Regulated Operating Subsidaries’ own systems or in conjunction with neighboring transmission systems. Third parties then transmit power through these local distribution systems to end-use consumers. The transmission of electricity by our Regulated Operating Subsidiaries is a central function to the provision of electricity to residential, commercial and industrial end-use consumers. The operations performed by our Regulated Operating Subsidiaries fall into the following categories:
•
asset planning;
•
engineering, design and construction;
•
asset protection and performance;
•
cyber security operations and engineering;
•
maintenance; and


7

•
real time operations.
Asset Planning
The Asset Planning group uses detailed system models and load forecasts to develop our system expansion capital plans. Expansion capital plans identify projects that address reliability issues and/or produce economic savings for customers by eliminating constraints.
The Asset Planning group submits projects into the MISO and SPP planning processes. As the regional planning authorities, MISO and SPP administer open and transparent processes through which the submitted Asset Planning group plans are vetted. MISO and SPP produce transmission expansion plans, which include projects to be constructed by their members, including our MISO Regulated Operating Subsidiaries and ITC Great Plains.
Engineering, Design and Construction
The Engineering, Design and Construction group is responsible for design, equipment specifications, maintenance plans and project management for capital and maintenance work. We work with outside contractors to perform various aspects of our engineering, design and construction, but retain internal technical experts who have experience with respect to the key elements of the transmission system such as substations, lines, equipment and protective relaying systems.
Asset Protection and Performance
The Asset Protection and Performance group is responsible for safety, human performance, security, and emergency preparedness and response. Given the inherent hazardous nature of the utilities industry, we proactively work to ensure that all personnel are free to perform in a safe and secure environment. Our focus is not to compromise the safety of our employees, contractors or the public in the course of providing the most reliable electricity transmission services.
Due to the growing trend in the theft of data, the security of hard assets including laptops, mechanical keys, badges, etc. is critical. We have established guidelines to help maintain the security of company assets and regularly monitor potential security threats.
Cyber Security Operations and Engineering
The Cyber Security Operations and Engineering group is responsible for protecting our digital assets and data by deploying advanced tools, techniques and monitoring systems designed to counteract and neutralize cyber threats.
Maintenance
We develop and track preventive maintenance plans to promote safe and reliable systems. By performing preventive maintenance on our assets, we can minimize the need for reactive maintenance, resulting in improved reliability. Our Regulated Operating Subsidiaries contract with ULCS, which is a division of Asplundh Tree Expert Co., to perform the majority of their maintenance. The agreement with ULCS provides us with access to an experienced and scalable workforce with knowledge of our system at an established rate.
Real Time Operations
System Operations — From our operations facilities in Michigan, transmission system operators continuously monitor the performance of the transmission systems of our Regulated Operating Subsidiaries, using software and communication systems to perform analysis to plan for contingencies and maintain security and reliability following any unplanned events on the system. Transmission system operators are also responsible for the switching and protective tagging function, taking equipment in and out of service to ensure capital construction projects and maintenance programs can be completed safely and reliably.
Local Balancing Authority Operator — Under the functional control of MISO, ITCTransmission and METC operate their electric transmission systems as a combined LBA area, known as MECS. From our operations facilities in Michigan, our employees perform the LBA functions as outlined in MISO’s Balancing Authority Agreement. These functions include actual interchange data administration and verification as well as MECS LBA area emergency procedure implementation and coordination. Besides ITCTransmission and METC, our other Regulated Operating Subsidiaries are not responsible for LBA functions for their respective assets.


8

Operating Contracts
Our Regulated Operating Subsidiaries have various operating contracts, including numerous interconnection agreements with generation and transmission providers that address terms and conditions of interconnection. The following significant agreements exist at our Regulated Operating Subsidiaries:
ITCTransmission
DTE Electric operates the electric distribution system to which ITCTransmission’s transmission system connects. A set of three operating contracts sets forth the terms and conditions related to DTE Electric’s and ITCTransmission’s ongoing working relationship. These contracts include the following:
Master Operating Agreement. The MOA governs the primary day-to-day operational responsibilities of ITCTransmission and DTE Electric. The MOA identifies the control area coordination services that ITCTransmission is obligated to provide to DTE Electric and certain generation-based support services that DTE Electric is required to provide to ITCTransmission.
Generator Interconnection and Operation Agreement. The GIOA established, re-established and maintains the direct electricity interconnection of DTE Electric’s electricity generating assets with ITCTransmission’s transmission system for the purposes of transmitting electric power from and to the electricity generating facilities.
Coordination and Interconnection Agreement. The CIA governs the rights, obligations and responsibilities of ITCTransmission and DTE Electric regarding, among other things, the operation and interconnection of DTE Electric’s distribution system and ITCTransmission’s transmission system, and the construction of new facilities or modification of existing facilities. Additionally, the CIA allocates costs for operation of supervisory, communications and metering equipment.
METC
Consumers Energy operates the electric distribution system to which METC’s transmission system connects. METC is a party to a number of operating contracts with Consumers Energy that govern the operations and maintenance of its transmission system. These contracts include the following:
Amended and Restated Easement Agreement. Under the Easement Agreement, Consumers Energy provides METC with an easement to the land on which a majority of METC’s transmission towers, poles, lines and other transmission facilities used to transmit electricity for Consumers Energy and others are located. METC pays Consumers Energy an annual rent for the easement and also pays for any rentals, property taxes and other fees related to the property covered by the Easement Agreement.
Amended and Restated Operating Agreement. Under the Operating Agreement, METC is responsible for maintaining and operating its transmission system, providing Consumers Energy with information and access to its transmission system and related books and records, administering and performing the duties of control area operator (that is, the entity exercising operational control over the transmission system) and, if requested by Consumers Energy, building connection facilities necessary to permit interaction with new distribution facilities built by Consumers Energy.
Amended and Restated Purchase and Sale Agreement for Ancillary Services. Since METC does not own any generating facilities, it must procure ancillary services from third party suppliers, such as Consumers Energy. Currently, under the Ancillary Services Agreement, METC pays Consumers Energy for providing certain generation-based services necessary to support the reliable operation of the bulk power grid, such as voltage support and generation capability and capacity to balance loads and generation.
Amended and Restated Distribution-Transmission Interconnection Agreement. The DT Interconnection Agreement, provides for the interconnection of Consumers Energy’s distribution system with METC’s transmission system and defines the continuing rights, responsibilities and obligations of the parties with respect to the use of certain of their own and the other party’s properties, assets and facilities.
Amended and Restated Generator Interconnection Agreement. The Generator Interconnection Agreement specifies the terms and conditions under which Consumers Energy and METC maintain the interconnection of Consumers Energy’s generation resources and METC’s transmission assets.


9

ITC Midwest
IP&L operates the electric distribution system to which ITC Midwest’s transmission system connects. ITC Midwest is a party to a number of operating contracts with IP&L that govern the operations and maintenance of its transmission system. These contracts include the following:
Distribution-Transmission Interconnection Agreement. The DTIA governs the rights, responsibilities and obligations of ITC Midwest and IP&L, with respect to the use of certain of their own and the other party’s property, assets and facilities and the construction of new facilities or modification of existing facilities.
Large Generator Interconnection Agreement. ITC Midwest, IP&L and MISO entered into the LGIA in order to establish, re-establish and maintain the direct electricity interconnection of IP&L’s electricity generating assets with ITC Midwest’s transmission system for the purposes of transmitting electric power from and to the electricity generating facilities.
Operations Services Agreement For 34.5 kV Transmission Facilities. ITC Midwest and IP&L entered into the OSA under which IP&L performs certain operations functions for ITC Midwest’s 34.5 kV transmission system on behalf of ITC Midwest. The OSA provides that when ITC Midwest upgrades 34.5 kV facilities to higher operating voltages it may notify IP&L of the change and the OSA is no longer applicable to those facilities.
ITC Great Plains
Amended and Restated Maintenance Agreement. Mid-Kansas and ITC Great Plains have entered into the Mid-Kansas Agreement pursuant to which Mid-Kansas has agreed to perform various field operations and maintenance services related to certain ITC Great Plains assets.
ITC Interconnection
ITC Interconnection acquired certain transmission assets from a merchant generating company and placed a 345kV transmission line in service. As a result, ITC Interconnection is a TO in PJM and is subject to rate regulation by the FERC. The revenues earned by ITC Interconnection are based on its facilities reimbursement agreement with the merchant generating company.
Regulatory Environment
Many regulators and public policy makers support the need for further investment in the transmission grid. The growth and changing mix of electricity generation, wholesale power sales and consumption combined with historically inadequate transmission investment have resulted in significant transmission constraints across the United States and increased stress on aging equipment. These problems will continue without increased investment in transmission infrastructure. Transmission system investments can also increase system reliability and reduce the frequency of power outages. Such investments can reduce transmission constraints and improve access to lower cost generation resources, resulting in a lower overall cost of delivered electricity for end-use consumers. The DOE has established the Office of Electricity that focuses on working with reliability experts from the power industry, state governments and their Canadian counterparts to improve grid reliability and increase investment in the country’s electric infrastructure. In addition, the FERC has signaled its desire for substantial new investment in the transmission sector by implementing various financial and other incentives.
The FERC has also issued orders to promote non-discriminatory transmission access for all transmission customers. In the United States, electric transmission assets are predominantly owned, operated and maintained by utilities that also own electricity generation and distribution assets, known as vertically integrated utilities. The FERC has recognized that the vertically-integrated utility model inhibits the provision of non-discriminatory transmission access and, in order to alleviate this potential discrimination, the FERC has mandated that all transmission systems over which it has jurisdiction must be operated in a comparable, non-discriminatory manner such that any seller of electricity affiliated with a TO or transmission operator is not provided with preferential treatment. The FERC has also indicated that independent transmission companies can play a prominent role in furthering its policy goals and has encouraged the legal and functional separation of transmission operations from generation and distribution operations.
The FERC requires compliance with certain reliability standards by TOs and may take enforcement actions for violations, including the imposition of substantial fines. NERC is responsible for developing and enforcing these mandatory reliability standards. We continually assess our transmission systems against standards established


10

by NERC, as well as the standards of applicable regional entities under NERC that have been delegated certain authority for the purpose of proposing and enforcing reliability standards.
Finally, utility holding companies are subject to FERC regulations related to access to books and records in addition to the requirement of the FERC to review and approve mergers and consolidations involving utility assets and holding companies in certain circumstances.
Federal Regulation
As electric transmission companies, our Regulated Operating Subsidiaries charge rates that are regulated by the FERC. The FERC is an independent regulatory commission within the DOE that regulates the interstate transmission and certain wholesale sales of natural gas, the transmission of oil and oil products by pipeline and the transmission and wholesale sales of electricity in interstate commerce. The FERC also administers accounting and financial reporting regulations and standards of conduct for the companies it regulates. In 1996, in order to facilitate open access transmission for participants in wholesale power markets, the FERC issued Order No. 888. Order No. 888 encouraged investor owned utilities to cede operational control over their transmission systems to ISOs, which are not-for-profit entities.
As an alternative to ceding operating control of their transmission assets to ISOs, certain investor owned utilities began to promote the formation of for-profit transmission companies, which would assume control of the operation of the grid. In 1999, the FERC issued Order No. 2000, which strongly encouraged utilities to voluntarily transfer operational control of their transmission systems to RTOs. RTOs, as envisioned in Order No. 2000, would assume many of the functions of an ISO, but the FERC permitted greater flexibility with regard to the organization and structure of RTOs than it had for ISOs. RTOs could accommodate the inclusion of independently owned, for-profit companies that own transmission assets within their operating structure. Independent ownership would facilitate not only the independent operation of the transmission systems, but also the formation of companies with a greater financial interest in maintaining and augmenting the capacity and reliability of those systems. RTOs, such as MISO and SPP, monitor electric reliability and are responsible for coordinating the operation of the wholesale electric transmission system and ensuring fair, non-discriminatory access to the transmission grid.
In 2011, the FERC issued Order No. 1000, which amends certain existing transmission planning and cost allocation requirements to ensure that FERC-jurisdictional services are provided at just and reasonable rates and on a basis that is just and reasonable and not unduly discriminatory or preferential. Order No. 1000 can create competition for certain future transmission projects, including within our current operating areas.
Revenue Requirement Calculations and Cost Sharing for Projects with Regional Benefits
The cost-based Formula Rates used by our Regulated Operating Subsidiaries include revenue requirement calculations for various types of projects. Network revenues continue to be the largest component of revenues recovered through our Formula Rates. However, regional cost sharing revenues have experienced long-term growth as a result of projects that have been identified as having regional benefits and are therefore eligible for regional cost recovery. Separate calculations of revenue requirement are performed for projects that have been approved for regional cost sharing.
We have projects that are eligible for regional cost sharing under the MISO tariff, such as certain network upgrade projects, and the MVPs, including our portions of the four MVPs in the ITC Midwest footprint and the Thumb Loop Project in the Michigan footprint. Additionally, certain projects at ITC Great Plains are eligible for recovery through a region-wide charge in the SPP tariff, including three regional cost sharing projects in Kansas.
State Regulation
The regulatory agencies in the states where our Regulated Operating Subsidiaries’ assets are located do not have jurisdiction over our rates or terms and conditions of service. However, they typically have jurisdiction over siting of transmission facilities and related matters as described below. Additionally, we are subject to the regulatory oversight of various state environmental quality departments for compliance with any state environmental standards and regulations.


11

ITCTransmission, METC and ITC Interconnection
Michigan
The Michigan Public Service Commission has jurisdiction over the siting of certain transmission facilities. Additionally, ITCTransmission, METC and ITC Interconnection have the right as independent transmission companies to condemn property in the state of Michigan for the purposes of building or maintaining transmission facilities.
ITCTransmission, METC and ITC Interconnection are also subject to the regulatory oversight of the Michigan Department of Environmental Quality, the Michigan Department of Natural Resources and certain local authorities for compliance with all environmental standards and regulations.
ITC Midwest
Iowa
The Iowa Utilities Board has the power of supervision over the construction, operation and maintenance of transmission facilities in Iowa by any entity, which includes the power to issue franchises. Iowa law further provides that any entity granted a franchise by the Iowa Utilities Board is vested with the power of condemnation in Iowa to the extent the Iowa Utilities Board approves and deems necessary for public use. A city has the power, pursuant to Iowa law, to grant a franchise to erect, maintain and operate transmission facilities within the city, which franchise may regulate the conditions required and manner of use of the streets and public grounds of the city and may confer the power to appropriate and condemn private property.
ITC Midwest also is subject to the regulatory oversight of certain state agencies (including the Iowa Department of Natural Resources) and certain local authorities with respect to the issuance of environmental, highway, railroad and similar permits.
Minnesota
The Minnesota Public Utilities Commission has jurisdiction over the construction, siting and routing of new transmission lines or upgrades of existing lines through Minnesota’s Certificate of Need and Route Permit Processes. Transmission companies are also required to participate in the state’s Biennial Transmission Planning Process and are subject to the state’s preventative maintenance requirements. Pursuant to Minnesota law, ITC Midwest has the right as an independent transmission company to condemn property in the state of Minnesota for the purpose of building new transmission facilities.
ITC Midwest is also subject to the regulatory oversight of the Minnesota Pollution Control Agency, the Minnesota Department of Natural Resources, the Minnesota Public Utilities Commission in conjunction with the Department of Commerce and certain local authorities for compliance with applicable environmental standards and regulations.
Illinois
The Illinois Commerce Commission exercises jurisdiction over the siting of new transmission lines through its requirements for Certificates of Public Convenience and Necessity and Right-Of-Way acquisition that apply to construction of new or upgraded facilities.
ITC Midwest is also subject to the regulatory oversight of the Illinois Environmental Protection Agency, the Illinois Department of Natural Resources, the Illinois Pollution Control Board and certain local authorities for compliance with all environmental standards and regulations.
Missouri
Because ITC Midwest is a “public utility” and an “electrical corporation” under Missouri law, the Missouri Public Service Commission has jurisdiction to determine whether ITC Midwest may operate in such capacity. The Missouri Public Service Commission also exercises jurisdiction with regard to other non-rate matters affecting this Missouri asset such as transmission substation construction, general safety and the transfer of the franchise or property.
ITC Midwest is also subject to the regulatory oversight of the Missouri Department of Natural Resources for compliance with all environmental standards and regulations relating to this transmission line.


12

Wisconsin
ITC Midwest is a “public utility” and independent TO in Wisconsin. The Public Service Commission of Wisconsin granted ITC Midwest a certificate of authority to transact public utility business in the state. The Public Service Commission of Wisconsin also recognized ITC Holdings as a public utility holding company under Wisconsin statutes.
The Public Service Commission of Wisconsin exercises jurisdiction over the siting of new transmission lines through the issuance of certificates of authority and certificates of public convenience and necessity. Upon receipt of such certificates for a transmission project, ITC Midwest has condemnation authority as a foreign transmission provider under Wisconsin law. ITC Midwest is also subject to the jurisdiction of certain local and state agencies, including the Wisconsin Department of Natural Resources, relating to environmental and road permits.
ITC Great Plains
Kansas
ITC Great Plains is a “public utility” and an “electric utility” in Kansas pursuant to state statutes. The KCC issued an order approving the issuance of a limited certificate of convenience to ITC Great Plains for the purposes of building, owning and operating SPP transmission projects in Kansas. In addition to its certificate of authority, the KCC has jurisdiction over the siting of electric transmission lines.
ITC Great Plains is also subject to the regulatory oversight of the Kansas Department of Health and Environment for compliance with all environmental standards and regulations relating to the construction phase of any transmission line.
Oklahoma
ITC Great Plains has approval from the Oklahoma Corporation Commission to operate in Oklahoma, pursuant to Oklahoma statutes as an electric public utility providing only transmission services. The Oklahoma Corporation Commission does not exercise jurisdiction over the siting of any transmission lines.
ITC Great Plains may be subject to the regulatory oversight of Oklahoma Department of Environmental Quality for compliance with environmental standards and regulations relating to construction of proposed transmission lines.
Sources of Revenue
See “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Significant Components of Results of Operations — Revenues” for a discussion of our principal sources of revenue.
Seasonality
The cost-based Formula Rates in effect for our Regulated Operating Subsidiaries, as discussed in “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cost-Based Formula Rates with True-Up Mechanism,” mitigate the seasonality of net income for our Regulated Operating Subsidiaries. Our Regulated Operating Subsidiaries accrue or defer revenues to the extent that the actual revenue requirement for the reporting period is higher or lower, respectively, than the amounts billed relating to that reporting period. For example, to the extent that amounts billed are less than our revenue requirement for a reporting period, a revenue accrual is recorded for the difference and the difference results in no net income impact.
Operating cash flows are seasonal at our MISO Regulated Operating Subsidiaries, in that cash received for revenues is typically higher in the summer months when peak load is higher.
Principal Customers
Our principal transmission service customers are DTE Electric, Consumers Energy and IP&L, which accounted for approximately 21.1%, 23.2% and 24.8%, respectively, of our consolidated billed revenues for the year ended December 31, 2019. One or more of these customers together have consistently represented a significant percentage of our operating revenue. These percentages of total billed revenues of DTE Electric, Consumers Energy and IP&L include the collection of 2017 revenue accruals and deferrals and exclude any amounts for the 2019 revenue accruals and deferrals that were included in our 2019 operating revenues, but will not be billed to our customers until 2021. Refer to “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cost-Based Formula Rates with True-Up Mechanism” for a discussion on the difference


13

between billed revenues and operating revenues. Our remaining revenues were generated from providing service to other entities such as alternative energy suppliers, power marketers and other wholesale customers that provide electricity to end-use consumers and from transaction-based capacity reservations. Nearly all of our revenues are from transmission customers in the United States. Although we may recognize allocated revenues from time to time from Canadian entities reserving transmission over the Ontario or Manitoba interface, these revenues have not been and are not expected to be material to us.
Billing
MISO and SPP are responsible for billing and collecting the majority of our transmission service revenues as well as independently administering the transmission tariff in their respective service territory. As the billing agents for our MISO Regulated Operating Subsidiaries and ITC Great Plains, MISO and SPP independently bill DTE Electric, Consumers Energy, IP&L and other customers on a monthly basis and collect fees for the use of our transmission systems.
See “Item 7A Quantitative and Qualitative Disclosures about Market Risk — Credit Risk” for discussion of our credit policies.
Competition
Each of our MISO Regulated Operating Subsidiaries operates the primary transmission system in its respective service area and has limited competition for certain projects. However, due to the implementation of the FERC Order No. 1000, other entities with transmission development initiatives may compete with us by seeking approval to be named the party authorized to build new capital projects that we are also pursuing. Our subsidiaries may also compete with other entities on development opportunities for transmission investment in locations outside of our existing service areas. See further discussion of Order No. 1000 above under “Regulatory Environment — Federal Regulation.”
Employees
As of December 31, 2019, we had 707 employees. We consider our relations with our employees to be good.
Environmental Matters
See “Environmental Matters” in Note 19 to the consolidated financial statements.
Available Information Under the Securities Exchange Act of 1934
Our Internet address is http://www.itc-holdings.com. Visit our website to learn more about us. Financial and other material information regarding us is routinely posted on our website and is readily accessible. All of our reports filed pursuant to Section 13(a) or 15(d) of the Exchange Act, including our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports, can be accessed free of charge through our website. These reports are available as soon as practicable after they are electronically filed with the SEC. The information on our website is not incorporated by reference into this report.
ITEM 1A.     RISK FACTORS.
Risks Related to Our Business
Certain elements of our Regulated Operating Subsidiaries’ Formula Rates have been and can be challenged, which could result in lowered rates and/or refunds of amounts previously collected and thus may have an adverse effect on our business, financial condition, results of operations and cash flows.
Our Regulated Operating Subsidiaries provide transmission service under rates regulated by the FERC. The FERC has approved the cost-based Formula Rates used by our Regulated Operating Subsidiaries to calculate their respective annual revenue requirements, but it has not expressly approved the amount of actual capital and operating expenditures to be used in the Formula Rates. All aspects of our Regulated Operating Subsidiaries’ rates approved by the FERC, including the Formula Rate templates, the rates of return on the actual equity portion of their respective capital structures and the approved capital structures, are subject to challenge by interested parties at the FERC, or by the FERC on its own initiative in a proceeding under Section 206 of the FPA. In addition, interested parties may challenge the annual implementation and calculation by our Regulated Operating Subsidiaries of their projected rates and Formula Rate true up pursuant to their approved Formula Rates under the Regulated Operating Subsidiaries’ Formula Rate implementation protocols. End-use consumers and entities


14

supplying electricity to end-use consumers may also attempt to influence government and/or regulators to change the rate setting methodologies that apply to our Regulated Operating Subsidiaries, particularly if rates for delivered electricity increase substantially. If a challenger can establish that any of these aspects are unjust, unreasonable, unduly discriminatory or preferential, then the FERC will make adjustments to them and/or disallow any of our Regulated Operating Subsidiaries’ inclusion of those aspects in the rate setting formula. This could result in lowered rates and/or refunds of amounts collected, any of which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Our actual capital investment may be lower than planned, which would cause a lower than anticipated rate base and would therefore result in lower revenues, earnings and associated cash flows compared to our current expectations. In addition, we expect to incur expenses related to the pursuit of development opportunities, which may be higher than forecasted.
Each of our Regulated Operating Subsidiaries’ rate base, revenues, earnings and associated cash flows are determined in part by additions to property, plant and equipment and when those additions are placed in service. If our operating subsidiaries’ capital investment and the resulting in-service property, plant and equipment are lower than anticipated for any reason, our operating subsidiaries will have a lower than anticipated rate base, thus causing their revenue requirements and future earnings and cash flows to be lower than anticipated.
Any capital investment at our Regulated Operating Subsidiaries may be lower than our published estimates due to, among other factors, the impact of:
•
actual or forecasted loads;
•
regional economic conditions;
•
weather conditions;
•
union strikes or labor shortages;
•
material and equipment prices and availability;
•
variances between estimated and actual costs of construction contracts awarded;
•
our ability to obtain financing for such expenditures, if necessary;
•
limitations on the amount of construction that can be undertaken on our system or transmission systems owned by others at any one time;
•
regulatory requirements relating to our rate construct, including our ability to recover costs;
•
the potential for greater competition;
•
environmental, siting or regional planning issues; and
•
legal proceedings.
Our ability to engage in construction projects resulting from pursuing these initiatives is subject to significant uncertainties, including the factors discussed above, and will depend on obtaining any necessary regulatory and other approvals for the project and for us to initiate construction, our achieving status as the builder of the project in some circumstances and other factors. In addition, projects may be canceled, the scope of planned projects may change, or projects may not be completed on time, any of which may adversely affect our level of investment or cause our projected investments to be inaccurate.
In addition, we expect to incur expenses to pursue strategic development investment opportunities. If these payments or expenses are higher than anticipated, our future results of operations, cash flows and financial condition could be materially and adversely affected.
The regulations to which we are subject may limit our ability to raise capital and/or pursue acquisitions, development opportunities or other transactions or may subject us to liabilities.
Each of our Regulated Operating Subsidiaries is a “public utility” under the FPA and, accordingly, is subject to regulation by the FERC. Approval of the FERC is required under Section 203 of the FPA for a disposition or acquisition of regulated public utility facilities, either directly or indirectly through a holding company. Such approval is also required to acquire a significant interest in securities of a public utility. Section 203 of the FPA also provides


15

the FERC with explicit authority over utility holding companies’ purchases or acquisitions of, and mergers or consolidations with, a public utility. Finally, each of our Regulated Operating Subsidiaries must also seek approval by the FERC under Section 204 of the FPA for issuances of its securities (including debt securities). If we are unable to obtain the necessary FERC approvals for potential acquisitions, dispositions or merger activities, or to raise capital, our strategic and growth opportunities may be limited. This could have an adverse impact on our consolidated results of operations, cash flows and financial condition.
We are also pursuing development projects for construction of transmission facilities and interconnections with generating resources. These projects may require regulatory approval by Federal agencies, including the FERC, applicable RTOs and state and local regulatory agencies. Failure to secure such regulatory approval for new strategic development projects could adversely affect our ability to grow our business and increase our revenues. If we fail to obtain these approvals when necessary, we may incur liabilities for such failure.
Changes in energy laws, regulations or policies could impact our business, financial condition, results of operations and cash flows.
Each of our Regulated Operating Subsidiaries is regulated by the FERC as a “public utility” under the FPA and is a TO in MISO, SPP or PJM. We cannot predict whether the approved rate methodologies for any of our Regulated Operating Subsidiaries will be changed. In addition, the U.S. Congress periodically considers enacting energy legislation that could assign new responsibilities to the FERC, modify provisions of the FPA or provide the FERC or another entity with increased authority to regulate transmission matters. Our Regulated Operating Subsidiaries may be affected by any such changes in federal energy laws, regulations or policies in the future. While our Regulated Operating Subsidiaries are subject to the FERC’s exclusive jurisdiction for purposes of rate regulation, changes in state laws affecting other matters, such as transmission siting and construction, could limit investment opportunities available to us.
Each of our MISO Regulated Operating Subsidiaries depends on its primary customer for a substantial portion of its revenues, and any material failure by those primary customers to make payments for transmission services could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Each of ITCTransmission, METC and ITC Midwest derive a substantial portion of their revenues from the transmission of electricity to the local distribution facilities of DTE Electric, Consumers Energy and IP&L, respectively. Each of these customers is expected to constitute the majority of the revenues of the respective MISO Regulated Operating Subsidiary for the foreseeable future. Any material failure by DTE Electric, Consumers Energy or IP&L to make payments for transmission services could have an adverse effect on our business, financial condition, results of operations and cash flows.
A significant amount of the land on which our assets are located is subject to easements, mineral rights and other similar encumbrances. As a result, we must comply with the provisions of various easements, mineral rights and other similar encumbrances, which may adversely impact our ability to complete construction projects in a timely manner.
METC does not own the majority of the land on which its electric transmission assets are located. Instead, under the provisions of the Easement Agreement, METC pays an annual rent to Consumers Energy in exchange for rights-of-way, leases, fee interests and licenses which allow METC to use the land on which its transmission lines are located. Under the terms of the Easement Agreement, METC’s easement rights could be eliminated if METC fails to meet certain requirements, such as paying contractual rent to Consumers Energy in a timely manner. Additionally, a significant amount of the land on which our other subsidiaries’ assets are located is subject to easements, mineral rights and other similar encumbrances. As a result, they must comply with the provisions of various easements, mineral rights and other similar encumbrances, which may adversely impact their ability to complete their construction projects in a timely manner.
We contract with third parties to provide services for certain aspects of our business. If any of these agreements are terminated, we may face a shortage of labor or replacement contractors to provide the services formerly provided by these third parties.
We enter into various agreements and arrangements with third parties to provide services for construction, maintenance and operations of certain aspects of our business, and we utilize the services of contractors to a significant extent. If any of these agreements or arrangements is terminated for any reason, it could result in a


16

shortage of a readily available workforce to provide such services and we may face difficulty finding a qualified replacement workforce. In such a situation, if we are unable to find adequate replacements for contractors in a timely manner, it could have an adverse effect on our results of operations and the ability to carry on our business.
Hazards associated with high-voltage electricity transmission may result in suspension of our operations, costly litigation or the imposition of civil or criminal penalties.
Our operations are subject to the usual hazards associated with high-voltage electricity transmission, including explosions, fires, mechanical failure, unscheduled downtime, equipment interruptions, remediation, chemical spills, discharges or releases of toxic or hazardous substances or gases and other environmental risks. These hazards can cause personal injury and loss of life, severe damage to or destruction of property and equipment and environmental damage, and may result in suspension of operations, litigation by aggrieved parties and the imposition of civil or criminal penalties which may have a material adverse effect on our business, financial condition and results of operations. We maintain property and casualty insurance, but we are not fully insured against all potential hazards incident to our business, such as damage to poles, towers and lines or losses caused by outages.
We are subject to environmental regulations and to laws that can give rise to substantial liabilities from environmental contamination.
We are subject to federal, state and local environmental laws and regulations, which impose limitations on the discharge of pollutants into the environment, establish standards for the management, treatment, storage, transportation and disposal of solid and hazardous wastes and hazardous materials, and impose obligations to investigate and remediate contamination in certain circumstances. Liabilities relating to investigation and remediation of contamination, as well as other liabilities concerning hazardous materials or contamination such as claims for personal injury or property damage, may arise at many locations, including formerly owned or operated properties and sites where wastes have been treated or disposed of, as well as properties we currently own or operate. Such liabilities may arise even where the contamination does not result from noncompliance with applicable environmental laws. Under a number of environmental laws, such liabilities may also be joint and several, meaning that a party can be held responsible for more than its share of the liability involved, or even the entire share.
We have incurred expenses in connection with environmental compliance, and we anticipate that we will continue to do so in the future. Failure to comply with the extensive environmental laws and regulations applicable to us could result in significant civil or criminal penalties and remediation costs. Our assets and operations also involve the use of materials classified as hazardous, toxic or otherwise dangerous. Some of our facilities and properties are located near environmentally sensitive areas such as wetlands and habitats of endangered or threatened species. In addition, certain properties in which we operate are, or are suspected of being, affected by environmental contamination. Compliance with these laws and regulations, and liabilities concerning contamination or hazardous materials, may adversely affect our costs and, therefore, our business, financial condition and results of operations.
If amounts billed for transmission service for our Regulated Operating Subsidiaries’ transmission systems are lower than expected, or our actual revenue requirements are higher than expected, the timing of actual collection of our total revenues would be delayed.
If amounts billed for transmission service are lower than expected, the timing of actual collections of our Regulated Operating Subsidiaries’ total revenue requirement would likely be delayed until such circumstances are adjusted through the true-up mechanism, which would be settled within a two-year period, in our Regulated Operating Subsidiaries’ Formula Rates. Lower than expected amounts collected could result from lower network load or point-to-point transmission service on our Regulated Operating Subsidiaries’ transmission systems due to a weak economy, changes in the nature or composition of the transmission assets of our Regulated Operating Subsidiaries and surrounding areas, poor transmission quality of neighboring transmission systems, or for any other reason. In addition, if the revenue requirements of our Regulated Operating Subsidiaries are higher than expected, the timing of actual collection of our Regulated Operating Subsidiaries' total revenue requirements would likely be delayed until such circumstances are reflected through the true-up mechanism, which would be settled within a two-year period, in our Regulated Operating Subsidiaries' Formula Rates. This could be due to higher actual expenditures compared to the forecasted expenditures used to develop their billing rates or for any other reason. The effect of such under-collection would be to reduce the amount of our available cash resources from what we had expected, until such under-collection is corrected through the true-up mechanism in the Formula Rate template, which may require us to increase our outstanding indebtedness, thereby reducing our available


17

borrowing capacity, and may require us to pay interest at a rate that exceeds the interest to which we are entitled in connection with the operation of the true-up mechanism.
We are subject to various regulatory requirements, including reliability standards; contract filing requirements; reporting, recordkeeping and accounting requirements; and transaction approval requirements. Violations of these requirements, whether intentional or unintentional, may result in penalties that, under some circumstances, could have a material adverse effect on our business, financial condition, results of operations and cash flows.
The various regulatory requirements to which we are subject include reliability standards established by the NERC, which acts as the nation’s Electric Reliability Organization approved by the FERC in accordance with Section 215 of the FPA. These standards address operation, planning and security of the bulk power system, including requirements with respect to real-time transmission operations, emergency operations, vegetation management, critical infrastructure protection and personnel training. Failure to comply with these requirements can result in monetary penalties as well as non-monetary sanctions. Monetary penalties vary based on an assigned risk factor for each potential violation, the severity of the violation and various other circumstances, such as whether the violation was intentional or concealed, whether there are repeated violations, the degree of the violator’s cooperation in investigating and remediating the violation and the presence of a compliance program, and such penalties can be substantial. Non-monetary sanctions include potential limitations on the violator’s activities or operation and placing the violator on a watchlist for major violators. If any of our subsidiaries violate the NERC reliability standards, even unintentionally, in any material way, any penalties or sanctions imposed against us could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Certain of our subsidiaries are also subject to requirements under Sections 203 and 205 of the FPA for approval of transactions; reporting, recordkeeping and accounting requirements; and for filing contracts related to the provision of jurisdictional services. Under the FERC policy, failure to file jurisdictional agreements on a timely basis may result in foregoing the time value of revenues collected under the agreement, but not to the point where a loss would be incurred. The failure to obtain timely approval of transactions subject to FPA Section 203, or to comply with applicable reporting, recordkeeping or accounting requirements under FPA Section 205, could subject us to penalties that could have a material adverse effect on our financial condition, results of operations and cash flows.
Acts of war, terrorist attacks, natural disasters, severe weather and other catastrophic events may have a material adverse effect on our business, financial condition, results of operations and cash flows.
Acts of war, terrorist attacks, natural disasters, severe weather and other catastrophic events may negatively affect our business, financial condition and cash flows in unpredictable ways, such as increased security measures and disruptions of markets. Energy related assets, including, for example, our transmission facilities and DTE Electric’s, Consumers Energy’s and IP&L’s generation and distribution facilities that we interconnect with, may be at risk of acts of war and terrorist attacks, as well as natural disasters, severe weather and other catastrophic events. Such events or threats may have a material effect on the economy in general and could result in a decline in energy consumption, which may have a material adverse effect on our business, financial condition, results of operations and cash flows.
A cyber-attack or incident could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Various U.S. Government agencies have noted that external threat sources continue to seek to exploit, through cyber attacks, potential vulnerabilities in the U.S. energy infrastructure including electric transmission assets. These cyber threats and attacks are becoming more sophisticated and dynamic. Cyber security incidents could harm our business by limiting our transmission capabilities, delay our development and construction of new facilities or capital improvement projects on existing facilities or expose us to liability. Cyber attacks targeting our information systems could also impair our records, networks, systems and programs, or transmit viruses to other systems. Such events or the threat of such events may increase costs associated with heightened security requirements. In addition, if our major customers or suppliers experience a cyber attack it may reduce their ability to use our transmission facilities or service our transmission assets. If our business or those of our customers and suppliers are subject to a cyber attack, it may have a material adverse effect on our business, financial condition, results of operations and cash flows.


18

Changes in tax laws or regulations may negatively affect our results of operations, net income, financial condition, cash flows and credit metrics.
We are subject to taxation by various taxing authorities at the federal, state and local levels. Various representatives of the government, corporations, industry groups and the public continue to pursue changes to tax laws and regulations, and corporate tax reform continues to be a priority in many jurisdictions. Due to unique aspects of the treatment of taxes for regulated utilities, the impacts of changes in tax laws for us and our Regulated Operating Subsidiaries may differ from the impacts to other corporations generally. We cannot predict the timing or impacts of any future modifications or changes in tax laws. Changes in federal, state or local tax rates or other aspects of tax laws could materially and adversely affect our results of operations, net income, financial condition, cash flows, and credit metrics.
Risks Relating to Our Corporate and Financial Structure
ITC Holdings is a holding company with no operations, and unless we receive dividends or other payments from our subsidiaries, we may be unable to fulfill our cash obligations.
As a holding company with no business operations, ITC Holdings’ material assets consist primarily of the stock and membership interests in our subsidiaries. Our only sources of cash to meet our obligations are dividends and other payments received by us from time to time from our subsidiaries, the proceeds raised from the sale of our securities and borrowings under our various credit agreements. Each of our subsidiaries, however, is legally distinct from us and has no obligation, contingent or otherwise, to make funds available to us. The ability of each of our Regulated Operating Subsidiaries and our other subsidiaries to pay dividends and make other payments to us is subject to, among other things, the availability of funds, after taking into account capital expenditure requirements, the terms of its indebtedness, applicable state laws and regulations of the FERC and the FPA. Our Regulated Operating Subsidiaries target a FERC-approved capital structure of 60% equity and 40% debt that may limit the ability of our Regulated Operating Subsidiaries to use net assets for the payment of dividends to ITC Holdings. In addition, ITC Holdings’ right to receive any assets of any subsidiary, and therefore the right of its creditors to participate in those assets, will be effectively subordinated to the claims of that subsidiary’s creditors. If ITC Holdings does not receive cash or other assets from our subsidiaries, it may be unable to pay principal and interest on its indebtedness.

We have a considerable amount of debt and our reliance on debt financing may limit our ability to fulfill our debt obligations and/or to obtain additional financing.
We have a considerable amount of debt and our consolidated indebtedness includes various debt securities and borrowings, which utilize indentures, revolving and term loan credit agreements and commercial paper that we rely on as sources of capital and liquidity. Our capital structure can have several important consequences, including, but not limited to, the following:
•
If future cash flows are insufficient, we may not be able to make principal or interest payments on our debt obligations, which could result in the occurrence of an event of default under one or more of those debt instruments.
•
We may need to increase our indebtedness in order to make the capital expenditures and other expenses or investments planned by us.
•
Our indebtedness has the general effect of reducing our flexibility to react to changing business and economic conditions insofar as they affect our financial condition. A substantial portion of the dividends and payments in lieu of taxes we receive from our subsidiaries will be dedicated to the payment of interest on our indebtedness, thereby, reducing our available cash.
•
In the event that we are liquidated, the creditors of our subsidiaries will be entitled to payment in full of the subsidiaries’ indebtedness prior to making any payments to ITC Holdings for the payment of its indebtedness.
•
We currently have debt instruments outstanding with short-term maturities or relatively short remaining maturities. Our ability to secure additional financing prior to or after these facilities mature, if needed, may be substantially restricted by the existing level of our indebtedness and the restrictions contained in our debt instruments. Additionally, the interest rates at which we might secure additional financings may be higher than our currently outstanding debt instruments or higher than forecasted at any point in time, which could adversely affect our business, financial condition, results of operations and cash flows.


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•
Market conditions could affect our access to capital markets, restrict our ability to secure financing to make the capital expenditures and investments and pay other expenses planned by us which could adversely affect our business, financial condition, cash flows and results of operations.
We may incur substantial additional indebtedness in the future. The incurrence of additional indebtedness would increase the leverage-related risks described above.
Adverse changes in our credit ratings may negatively affect us.
Our ability to access capital markets is important to our ability to operate our business. Increased scrutiny of the energy industry and the impact of regulation, as well as changes in our financial performance and unfavorable conditions in the capital markets could result in credit agencies reexamining and downgrading our credit ratings. In addition, because we are a subsidiary of Fortis, a downgrade in Fortis’ credit rating could cause our credit rating to be downgraded as well, even if our creditworthiness has not otherwise deteriorated. A downgrade in our credit ratings could restrict or discontinue our ability to access capital markets at attractive rates and increase our borrowing costs. A rating downgrade could also increase the interest we pay on commercial paper and under our revolving and term loan credit agreements.
Certain provisions in our debt instruments limit our financial and operating flexibility.
Our debt instruments on a consolidated basis, including senior notes, secured notes, first mortgage bonds, revolving and term loan credit agreements and commercial paper, contain numerous financial and operating covenants that place significant restrictions on, among other things, our ability to:
•
incur additional indebtedness;
•
engage in sale and lease-back transactions;
•
create liens or other encumbrances;
•
enter into mergers, consolidations, liquidations or dissolutions, or sell or otherwise dispose of all or substantially all of our assets;
•
create and acquire subsidiaries; and
•
pay dividends or make distributions on our stock or on the stock or member capital of our subsidiaries.
In addition, the covenants require us to meet certain financial ratios, such as maintaining certain debt to capitalization ratios and certain funds from operations to debt levels. Our ability to comply with these and other requirements and restrictions may be affected by changes in economic or business conditions, results of operations or other events beyond our control. A failure to comply with the obligations contained in any of our debt instruments could result in acceleration of related debt and the acceleration of debt under other instruments evidencing indebtedness that may contain cross-acceleration or cross-default provisions.
ITEM 1B.     UNRESOLVED STAFF COMMENTS.
None.
ITEM 2.    PROPERTIES.
Our Regulated Operating Subsidiaries’ transmission facilities are located in Michigan, Iowa, Minnesota, Illinois, Missouri, Kansas and Oklahoma. Our MISO Regulated Operating Subsidiaries and ITC Great Plains have agreements with other utilities for the joint ownership of specific substations, transmission lines and other transmission assets. See Note 17 to the consolidated financial statements for more information on the jointly owned assets.
Our Regulated Operating Subsidiaries own the assets of transmission systems and related assets, including:
•
approximately 15,900 circuit miles of overhead and underground transmission lines rated at voltages of 34.5 kV to 345 kV, along with related transmission towers and poles;
•
station assets, such as transformers and circuit breakers, at approximately 660 stations and substations which either interconnect our Regulated Operating Subsidiaries’ transmission facilities or connect our Regulated Operating Subsidiaries’ facilities with generation or distribution facilities owned by others;


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•
other transmission equipment necessary to safely operate the system (e.g., monitoring and metering equipment);
•
warehouses and related equipment; and
•
associated land held in fee, rights-of-way and easements.
ITCTransmission owns a corporate headquarters facility and operations control room in Novi, Michigan and a facility in Ann Arbor, Michigan that includes a back-up operations control room, along with associated furniture, fixtures and office equipment for these facilities.
METC does not own the majority of the land on which its assets are located, but under the provisions of the Easement Agreement, METC has an easement to use the land, rights-of-way, leases and licenses in the land on which its transmission lines are located that are held or controlled by Consumers Energy. See “Item 1 Business - Operating Contracts - METC - Amended and Restated Easement Agreement.”
Our Regulated Operating Subsidiaries have issued certain First Mortgage Bonds and Senior Secured Notes. Under the terms of these instruments, the respective bondholders and noteholders have the benefit of a first mortgage lien on substantially all of the assets of the corresponding debt issuer. Refer to Note 11 to the consolidated financial statements for more information on the outstanding debt of our Regulated Operating Subsidiaries. As of December 31, 2019, there were no liens or encumbrances on the assets of ITC Interconnection.
The assets of our Regulated Operating Subsidiaries are suitable for electric transmission and adequate for the electricity demand in our service territory. We prioritize capital spending based in part on meeting reliability standards within the industry. This includes replacing and upgrading existing assets as needed.
ITEM 3.     LEGAL PROCEEDINGS.
We are involved in certain legal proceedings before various courts, governmental agencies and mediation panels concerning matters arising in the ordinary course of business. These proceedings include certain contract disputes, regulatory matters and pending judicial matters. We cannot predict the final disposition of such proceedings. We regularly review legal matters and record provisions for claims that are considered probable of loss.
Refer to Notes 6 and 19 to the consolidated financial statements for a description of certain pending legal proceedings, which description is incorporated herein by reference.
ITEM 4.     MINE SAFETY DISCLOSURES.
Not applicable.
PART II
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
ITC Holdings is a wholly-owned subsidiary of ITC Investment Holdings and ITC Holdings’ common stock is not publicly traded.
ITC Holdings paid dividends of $250 million and $200 million to our parent, ITC Investment Holdings, during the years ended December 31, 2019 and 2018, respectively. ITC Holdings also paid dividends of $83 million to ITC Investment Holdings in January 2020. The timing and amount of future dividends is subject to an approved dividend declaration from our Board of Directors, and is dependent upon cash flows, capital requirements, legislative and regulatory developments, and financial condition of ITC Holdings, among other factors deemed relevant.


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ITEM 6.     SELECTED FINANCIAL DATA.
The selected historical financial data presented below should be read together with our consolidated financial statements and the notes to those statements and “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations,” included elsewhere in this Form 10-K.
 
ITC Holdings and Subsidiaries
 
Year Ended December 31,
(In millions)
2019
 
2018
 
2017
 
2016
 
2015
OPERATING REVENUES (a) (b)
 
 
 
 
 
 
 
 
 
Transmission and other services
$
1,286

 
$
1,192

 
$
1,226

 
$
1,142

 
$
1,025

Formula Rate true-up
41

 
(36
)
 
(15
)
 
(17
)
 
20

Total operating revenues
1,327

 
1,156

 
1,211

 
1,125

 
1,045

OPERATING EXPENSES
 
 
 
 
 
 
 
 
 
Operation and maintenance
113

 
109

 
110

 
114

 
113

General and administrative (c) (d)
138

 
127

 
121

 
234

 
140

Depreciation and amortization
203

 
180

 
169

 
158

 
145

Taxes other than income taxes
118

 
109

 
103

 
93

 
82

Other operating (income) and expense, net
—

 
(4
)
 
(2
)
 
(1
)
 
(1
)
Total operating expenses (d)
572

 
521

 
501

 
598

 
479

OPERATING INCOME (d)
755

 
635

 
710

 
527

 
566

OTHER EXPENSES (INCOME)
 
 
 
 
 
 
 
 
 
Interest expense, net
224

 
224

 
224

 
211

 
204

Allowance for equity funds used during construction
(29
)
 
(33
)
 
(33
)
 
(35
)
 
(28
)
Other (income) and expenses, net (d)
—

 
3

 
4

 
8

 
6

Total other expenses (income) (d)
195

 
194

 
195

 
184

 
182

INCOME BEFORE INCOME TAXES
560

 
441

 
515

 
343

 
384

INCOME TAX PROVISION (e)
132

 
111

 
196

 
97

 
142

NET INCOME
$
428

 
$
330

 
$
319

 
$
246

 
$
242

____________________________
(a)
The decrease in operating revenues in 2018 was due to a reduction in taxes collected through our Regulated Operating Subsidiaries’ Formula Rates as a result of the reduction in the U.S. federal corporate income tax rate from 35% to 21% effective for tax years beginning after 2017.
(b)
We recognized an increase in operating revenues of $69 million in 2019 and a reduction in operating revenues of $80 million and $115 million in 2016 and 2015, respectively, relating to the refund obligations for the MISO ROE Complaints as described in Note 19 to the consolidated financial statements.
(c)
During 2016, we expensed external legal, advisory and financial services fees of $55 million related to the Merger Agreement and approximately $41 million due to the accelerated vesting of the share-based awards that occurred as a result of the Merger Agreement. The external and internal costs related to the Merger Agreement were recorded at ITC Holdings and have not been included as components of revenue requirement at our Regulated Operating Subsidiaries.
(d)
All amounts presented reflect the change in the authoritative guidance issued by the FASB regarding net periodic pension and postretirement benefit non-service costs which are now included in the line “Other (income) and expenses, net”. This change was adopted retrospectively by us in 2018.
(e)
The decrease in income tax provision in 2018 was due to the reduction in the U.S. federal corporate income tax rate from 35% to 21% effective for tax years beginning after 2017. During 2016, we recognized an income tax benefit of $27 million for excess tax deductions as a result of adopting the accounting guidance associated with share-based payments.


22

 
ITC Holdings and Subsidiaries
 
December 31,
(In millions)
2019
 
2018
 
2017
 
2016
 
2015
BALANCE SHEET DATA:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
4

 
$
6

 
$
66

 
$
8

 
$
14

Working capital (deficit)
(471
)
 
(308
)
 
(302
)
 
(400
)
 
(550
)
Property, plant and equipment, net
8,582

 
7,910

 
7,309

 
6,698

 
6,110

Goodwill
950

 
950

 
950

 
950

 
950

Total assets
10,058

 
9,329

 
8,823

 
8,223

 
7,555

Debt:
 
 
 
 
 
 
 
 
 
ITC Holdings
2,968

 
2,767

 
2,728

 
2,387

 
2,304

Regulated Operating Subsidiaries
2,839

 
2,571

 
2,373

 
2,203

 
2,125

Total debt
5,807

 
5,338

 
5,101

 
4,590

 
4,429

Total stockholder’s equity
$
2,232

 
$
2,051

 
$
1,920

 
$
1,901

 
$
1,709

 
ITC Holdings and Subsidiaries
 
Year Ended December 31,
(In millions)
2019
 
2018
 
2017
 
2016
 
2015
CASH FLOWS DATA:
 
 
 
 
 
 
 
 
 
Expenditures for property, plant and equipment
$
865

 
$
769

 
$
755

 
$
750

 
$
701

ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
Safe Harbor Statement Under The Private Securities Litigation Reform Act of 1995
Our reports, filings and other public announcements contain certain statements that describe our management’s beliefs concerning future business conditions, plans and prospects, growth opportunities, the outlook for our business and the electric transmission industry, and expectations with respect to various legal and regulatory proceedings based upon information currently available. Such statements are “forward-looking” statements within the meaning of the Private Securities Litigation Reform Act of 1995. Wherever possible, we have identified these forward-looking statements by words such as “will,” “may,” “anticipates,” “believes,” “intends,” “estimates,” “expects,” “forecasted,” “projects,” “likely” and similar phrases. These forward-looking statements are based upon assumptions our management believes are reasonable. Such forward-looking statements are based on estimates and assumptions and subject to significant risks and uncertainties which could cause our actual results, performance and achievements to differ materially from those expressed in, or implied by, these statements, including, among others, the risks and uncertainties listed in this report under “Item 1A Risk Factors” and in our other reports filed with the SEC from time to time.
Forward-looking statements speak only as of the date made and can be affected by assumptions we might make or by known or unknown risks and uncertainties. Many factors mentioned in our discussion in this report will be important in determining future results. Consequently, we cannot assure you that our expectations or forecasts expressed in such forward-looking statements will be achieved. Except as required by law, we undertake no obligation to publicly update any of our forward-looking or other statements, whether as a result of new information, future events or otherwise.
Statement on Prior Period Comparisons
This section of this Form 10-K generally discusses the financial condition, changes in financial condition and results of operations for the years ended December 31, 2019 and 2018 and provides year-to-year comparisons between the years ended December 31, 2019 and 2018. Discussions of such information for the year ended December 31, 2017 and year-to-year comparisons between the years ended December 31, 2018 and 2017 that are not included in this Form 10-K can be found in “Management’s Discussion and Analysis of Financial Condition


23

and Results of Operations” in Part II, Item 7 of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2018.
Overview
ITC Holdings and its subsidiaries are engaged in the transmission of electricity in the United States. ITC Holdings is a wholly-owned subsidiary of ITC Investment Holdings. Through our Regulated Operating Subsidiaries, we own and operate high-voltage electric transmission systems in Michigan’s Lower Peninsula and portions of Iowa, Minnesota, Illinois, Missouri, Kansas and Oklahoma that transmit electricity from generating stations to local distribution facilities connected to our transmission systems. Our business strategy is to own, operate, maintain and invest in transmission infrastructure in order to enhance system integrity and reliability, reduce transmission constraints and support new generating resources to interconnect to our transmission systems.
As electric transmission utilities with rates regulated by the FERC, our Regulated Operating Subsidiaries earn revenues for the use of their electric transmission systems by our customers, which include investor-owned utilities, municipalities, cooperatives, power marketers and alternative energy suppliers. As independent transmission companies, our Regulated Operating Subsidiaries are subject to rate regulation only by the FERC, and our cost-based rates are discussed below under “— Cost-Based Formula Rates with True-Up Mechanism” as well as in Note 6 to the consolidated financial statements.
Our Regulated Operating Subsidiaries’ primary operating responsibilities include maintaining, improving and expanding their transmission systems to meet their customers’ ongoing needs, scheduling outages on system elements to allow for maintenance and construction, maintaining appropriate system voltages and monitoring flows over transmission lines and other facilities to ensure physical limits are not exceeded.
Significant recent matters that influenced our financial condition, results of operations and cash flows for the year ended December 31, 2019 or that may affect future results include:
•
Our capital expenditures of $865 million at our Regulated Operating Subsidiaries during the year ended December 31, 2019, as described below under “— Capital Investment and Operating Results Trends,” resulting primarily from our focus on improving system reliability, increasing system capacity and upgrading the transmission network to support new generating resources, which includes electric transmission asset acquisitions from Consumers Energy of $77 million, of which $34 million is an acquisition premium that is excluded from rate base;
•
Debt issuances and repayments as described in Note 11 to the consolidated financial statements, including the issuance of Senior Secured Notes by METC, First Mortgage Bonds by ITCTransmission and borrowings under our revolving and term loan credit agreements and commercial paper program to fund capital investment at our Regulated Operating Subsidiaries as well as for general corporate purposes;
•
Issuance of the November 2019 Order related to the MISO ROE Complaints, as described in Note 19 to the consolidated financial statements, which resulted in a reduction to the base ROE to 9.88% for our MISO Regulated Operating Subsidiaries, reversal of the amount previously recorded as an estimated current regulatory liability for refunds relating to the Second Complaint and recording of a current regulatory liability for our MISO Regulated Operating Subsidiaries of $70 million as of December 31, 2019 for refunds relating to the Initial Complaint and the period from the date of the September 2016 Order to December 31, 2019;
•
The adoption of tax accounting method changes related to bonus depreciation and repairs and maintenance deductions during the fourth quarter of 2019, which did not have a significant impact on the consolidated financial statements as of and for the year ended December 31, 2019 but may impact future results; and
•
Two notices of inquiry issued by the FERC on March 21, 2019 seeking comments on (1) whether and how policies concerning the determination of the base ROE for electric utilities should be modified, and (2) its electric transmission incentives policy.
These items are discussed in more detail throughout “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Cost-Based Formula Rates with True-Up Mechanism
Our Regulated Operating Subsidiaries calculate their revenue requirements using cost-based Formula Rates that are effective without the need to file rate cases with the FERC, although the rates are subject to legal challenge


24

at the FERC. Under their cost-based formula, each of our Regulated Operating Subsidiaries separately calculates a revenue requirement based on financial information specific to each company. The calculation of projected revenue requirement for a future period is used to establish the transmission rate used for billing purposes. The calculation of actual revenue requirements for a historic period is used to calculate the amount of revenues recognized in that period and determine the over- or under-collection for that period.
Under these Formula Rates, our Regulated Operating Subsidiaries recover expenses and earn a return on and recover investments in property, plant and equipment on a current basis. The Formula Rates for a given year reflect forecasted expenses, property, plant and equipment, point-to-point revenues, network load at our MISO Regulated Operating Subsidiaries and other items for the upcoming calendar year to establish projected revenue requirements for each of our Regulated Operating Subsidiaries that are used as the basis for billing for service on their systems from January 1 to December 31 of that year. Our Formula Rates include a true-up mechanism, whereby our Regulated Operating Subsidiaries compare their actual revenue requirements to their billed revenues for each year to determine any over- or under-collection of revenue. The over- or under-collection typically results from differences between the projected revenue requirement used as the basis for billing and actual revenue requirement at each of our Regulated Operating Subsidiaries, or from differences between actual and projected monthly peak loads at our MISO Regulated Operating Subsidiaries. In the event billed revenues in a given year are more or less than actual revenue requirements, which are calculated primarily using information from that year’s FERC Form No. 1, our Regulated Operating Subsidiaries will refund or collect additional revenues, with interest, within a two-year period such that customers pay only the amounts that correspond to actual revenue requirements for that given period. This annual true-up ensures that our Regulated Operating Subsidiaries recover their allowed costs and earn their allowed returns.
See “Cost-Based Formula Rates with True-Up Mechanism” in Note 6 to the consolidated financial statements for further discussion of our Formula Rates and see “Rate of Return on Equity Complaints” in Note 19 to the consolidated financial statements for detail on ROE matters.


25

Illustrative Example of Formula Rate Setting
The Formula Rate setting example shown below is for illustrative purposes only and is not based on our actual financial data.
Line
Item
Instructions
Amount
1
Rate base (a)
 
$
1,000,000

2
Multiply by 13-month weighted average cost of capital (b)
 
8.38
%
3
Allowed return on rate base
(Line 1 x Line 2)
$
83,800

4
Recoverable operating expenses (including depreciation and amortization)
 
$
150,000

5
Income taxes (c)
 
37,500

6
Gross revenue requirement
(Line 3 + Line 4 + Line 5)
$
271,300

____________________________
(a)
Consists primarily of in-service property, plant and equipment, net of accumulated depreciation.
(b)
The weighted average cost of capital for purposes of this illustration is calculated below. The cost of capital for debt is included at a flat interest rate for purposes of this illustration and is not based on our actual cost of capital. The cost of capital rate for equity represents the current maximum allowed MISO ROE per the November 2019 Order on the Initial Complaint. See Note 19 to the consolidated financial statements for detail on ROE matters.
 
 
 
 
 
Weighted
 
 
 
 
 
Average
 
Percentage of
 
 
 
Cost of
 
Total Capitalization
 
Cost of Capital
 
Capital
Debt
40.00%
 
5.00% =
 
2.00
%
Equity
60.00%
 
10.63% =
 
6.38
%
 
100.00%
 
 
 
8.38
%
(c)
Represents an approximation of the federal and state income tax expense for purposes of this illustration and is not based on our actual tax expense.
Revenue Accruals and Deferrals — Effects of Monthly Peak Loads
For our MISO Regulated Operating Subsidiaries, monthly peak loads are used for billing network revenues, which currently is the largest component of our operating revenues. One of the primary factors that impacts the revenue accruals and deferrals at our MISO Regulated Operating Subsidiaries is actual monthly peak loads experienced as compared to those forecasted in establishing the annual network transmission rate. Under their cost-based Formula Rates that contain a true-up mechanism, our MISO Regulated Operating Subsidiaries accrue or defer revenues to the extent that their actual revenue requirement for the reporting period is higher or lower, respectively, than the amounts billed relating to that reporting period. Although monthly peak loads do not impact operating revenues recognized, network load affects the timing of our cash flows from transmission service. The monthly peak load of our MISO Regulated Operating Subsidiaries is generally impacted by weather and economic conditions and seasonally shaped with higher load in the summer months when cooling demand is higher.
ITC Great Plains does not receive revenue based on a peak load or a dollar amount per kW each month therefore, peak load does not have a seasonal effect on operating cash flows. The SPP tariff applicable to ITC Great Plains is billed ratably each month based on its annual projected revenue requirement posted annually by SPP.
Capital Investment and Operating Results Trends
We expect a long-term upward trend in rate base resulting from our anticipated capital investment, in excess of depreciation and any acquisition premiums, from our Regulated Operating Subsidiaries’ long-term capital investment programs to improve reliability, increase system capacity and upgrade the transmission network to support new generating resources. Investments in property, plant and equipment, when placed in-service upon completion of a capital project, are added to the rate base of our Regulated Operating Subsidiaries. While we expect increases in rate base to result in a corresponding long-term upward trend in revenues and earnings, our


26

revenues and earnings are also impacted by changes in our ROE or required refunds resulting from the resolution of the incentive adders complaints and MISO ROE Complaints, as described in Note 6 and Note 19 to the consolidated financial statements, or other future increases or decreases to our rates for incentive adders and base ROE.
Our Regulated Operating Subsidiaries strive for high reliability of their systems and improvement in system accessibility for all generation resources. The FERC requires compliance with certain reliability standards and may take enforcement actions against violators, including the imposition of substantial fines. NERC is responsible for developing and enforcing these mandatory reliability standards. We continually assess our transmission systems against standards established by NERC, as well as the standards of applicable regional entities under NERC that have been delegated certain authority for the purpose of proposing and enforcing reliability standards. We believe that we meet the applicable standards in all material respects, although further investment in our transmission systems and an increase in maintenance activities will likely be needed to maintain compliance, improve reliability and address any new standards that may be promulgated.
We also assess our transmission systems against our own planning criteria that are filed annually with the FERC. Based on our planning studies, we see needs to make capital investments to: (1) maintain and replace the current transmission infrastructure; (2) enhance system integrity and reliability and accommodate load growth; (3) upgrade physical and technological grid security; and (4) develop and build regional transmission infrastructure, including additional transmission facilities that will provide interconnection opportunities for generating facilities. The following table shows our actual and expected capital expenditures at our Regulated Operating Subsidiaries:
 
 
Actual Capital
 
Forecasted
 
 
Expenditures for the
 
Capital
 
 
year ended
 
Expenditures
(In millions)
 
December 31, 2019
 
2020 — 2024
Expenditures for property, plant and equipment (a)
 
$
865

 
$
3,746

____________________________
(a)
Amounts represent the cash payments to acquire or construct property, plant and equipment, as presented in the consolidated statements of cash flows. These amounts exclude non-cash additions to property, plant and equipment for the AFUDC equity as well as accrued liabilities for construction, labor and materials that have not yet been paid.
We are pursuing development projects that could result in a significant amount of capital investment, but we are not able to estimate the amounts we ultimately expect to invest or the timing of such investments. Refer to “Item 1 Business — Development of Business” for discussion of our development activities.
Investments in property, plant and equipment could be lower than expected due to a variety of factors, as described in “Item 1A Risk Factors”. In addition, investments in transmission network upgrades for generator interconnection projects could change from prior estimates significantly due to changes in the MISO queue for generation projects and other factors beyond our control.
Recent Developments
Rate of Return on Equity Complaints
Two complaints were filed with the FERC by combinations of consumer advocates, consumer groups, municipal parties and other parties challenging the base ROE in MISO. Prior to the filing of the MISO ROE Complaints, complaints were filed with the FERC regarding the regional base ROE rate for ISO New England TOs. See Note 19 to the consolidated financial statements for a summary of the MISO ROE Complaints and related proceedings.
Related FERC Orders
In April 2017, the D.C. Circuit Court vacated the precedent-setting FERC orders in the ISO New England matters that established and applied the two-step DCF methodology for the determination of base ROE. The court remanded the orders to the FERC for further justification of its establishment of the new base ROE for the ISO New England TOs. On October 16, 2018, in the New England matters, the FERC issued an order on remand which proposed a new methodology for 1) determining when an existing ROE is no longer just and reasonable; and 2) setting a new just and reasonable ROE if an existing ROE has been found not to be just and reasonable. The FERC established


27

a paper hearing on how the proposed new methodology should apply to the ISO New England TOs ROE complaint proceedings. The FERC issued a similar order, the November 2018 Order, in the MISO ROE Complaints, establishing a paper hearing on the application of the proposed new methodology to the proceedings pending before the FERC involving the MISO TOs’ ROE, including our MISO Regulated Operating Subsidiaries.
The November 2018 Order included preliminary illustrative calculations for the ROE that could have been established for the Initial Complaint, using the FERC's proposed methodology with financial data from the proceedings related to that complaint. The FERC’s preliminary calculations were not binding and could change, as significant changes to the methodology by the FERC were possible as a result of the paper hearing process. The November 2018 Order and our response to the order through briefs and reply briefs did not provide a reasonable basis for a change to the reserve or ROEs utilized for any of the complaint refund periods nor all subsequent periods. On March 21, 2019, the FERC issued a notice of inquiry seeking comments on whether and how policies concerning the determination of the base ROE for electric utilities should be modified, which is still pending. The FERC’s consideration of responses to this notice of inquiry may impact our future base ROE.
November 2019 Order
On November 21, 2019, the FERC issued an order on the MISO ROE Complaints. The FERC did not adopt the methodology proposed in the November 2018 Order, which had proposed using four financial models to establish the base ROE. Instead, the FERC determined that two financial models should be used to determine the base ROE. The FERC applied that methodology to the Initial Complaint period and determined that the base ROE for the Initial Complaint should be 9.88% and the top of the range of reasonableness for that period should be 12.24%. The FERC determined that this base ROE should apply during the first refund period of November 12, 2013 to February 11, 2015 and from the date of the September 2016 Order prospectively. In the November 2019 Order, the FERC also dismissed the Second Complaint. Therefore, based on the November 2019 Order, for the Second Complaint refund period from February 12, 2015 to May 11, 2016, no refund is due, and the base ROE for that period should be 12.38% plus applicable incentive adders. As a result, we have reversed the aggregate estimated current liability we had previously recorded for the Second Complaint, as noted below in “Financial Statement Impacts”. In addition, from May 12, 2016 to September 27, 2016, the base ROE should be 12.38% plus applicable incentive adders, because no complaint had been filed for that period and no refund is due during that period. The FERC ordered refunds to be made in accordance with the November 2019 Order within 30 days, but on December 18, 2019 the FERC granted a request from MISO for an extension until December 23, 2020 for settlement of the refunds. The MISO TOs, including our MISO Regulated Operating Subsidiaries, and several other parties filed requests for rehearing of the November 2019 Order. The MISO TOs filed their request for rehearing primarily on the basis that the methodology applied by the FERC in the November 2019 Order will not allow the MISO TOs to earn a reasonable rate of return on their investment, as required by precedent. On January 21, 2020, the FERC issued an order granting rehearings for further consideration.
In January 2020, certain complainants in the MISO ROE dockets filed an appeal of the September 2016 Order and the November 2019 Order at the D.C. Circuit Court. We believe that the appeal was premature and should be dismissed, but if not, we will respond in due course.
Financial Statement Impacts
As of December 31, 2019, we had recorded a current regulatory liability in the consolidated statements of financial position of $70 million to reflect amounts due to customers under the terms outlined in the November 2019 Order on the Initial Complaint and the period from the date of the September 2016 Order to December 31, 2019. We had recorded an aggregate estimated current regulatory liability in the consolidated statements of financial position of $151 million as of December 31, 2018 for the Second Complaint, which was reversed in November 2019 following the November 2019 Order. Although the November 2019 Order dismissed the Second Complaint with no refunds required, it is possible upon rehearing that our MISO Regulated Operating Subsidiaries will be required to provide refunds related to the Second Complaint and these refunds could be material. It is also possible, upon rehearing of the November 2019 Order, that the outcome may differ materially from the November 2019 Order. In 2017, $118 million, including interest, was refunded to customers of our MISO Regulated Operating Subsidiaries for the Initial Complaint based on the refund liability associated with the September 2016 Order.
Our MISO Regulated Operating Subsidiaries currently record revenues at the base ROE of 9.88% established in the November 2019 Order plus applicable incentive adders. See Note 6 to the consolidated financial statements for a summary of incentive adders for transmission rates.


28

The recognition of the obligations associated with the MISO ROE Complaints resulted in the following impacts to the consolidated statements of comprehensive income during each respective period:
 
Year Ended December 31,
(In millions)
2019
 
2018
 
2017
Revenue increase (decrease)
$
69

 
$
1

 
$
—

Interest expense increase (decrease)
(12
)
 
7

 
6

Estimated net income increase (decrease)
61

 
(4
)
 
(3
)
As of December 31, 2019, our MISO Regulated Operating Subsidiaries had a total of approximately $5 billion of equity in their collective capital structures for ratemaking purposes. Based on this level of aggregate equity, we estimate that each 10 basis point change in the authorized ROE would impact annual consolidated net income by approximately $5 million.
Challenges to Incentive Adders for Transmission Rates
On March 21, 2019, the FERC issued a notice of inquiry seeking comments on its electric transmission incentives policy, which is still pending. The FERC’s consideration of responses to this inquiry may impact the incentive adders that our Regulated Operating Subsidiaries are authorized to apply to their base ROEs. See Note 6 to the consolidated financial statements for a summary of incentive adders for transmission rates.
MISO Regulated Operating Subsidiaries
On April 20, 2018, Consumers Energy, IP&L, Midwest Municipal Transmission Group, Missouri River Energy Services, Southern Minnesota Municipal Power Agency and WPPI Energy filed a complaint with the FERC under section 206 of the FPA, challenging the adders for independent transmission ownership that are included in transmission rates charged by the MISO Regulated Operating Subsidiaries. The adders for independent transmission ownership allowed up to 50 basis points or 100 basis points to be added to the MISO Regulated Operating Subsidiaries’ authorized ROE, subject to any ROE cap established by the FERC. On October 18, 2018, the FERC issued an order granting the complaint in part, setting revised adders for independent transmission ownership for each of the MISO Regulated Operating Subsidiaries to 25 basis points, and requiring the MISO Regulated Operating Subsidiaries to include the revised adders, effective April 20, 2018, in their Formula Rates. In addition, the order directed the MISO Regulated Operating Subsidiaries to provide refunds, with interest, for the period from April 20, 2018 through October 18, 2018. The MISO Regulated Operating Subsidiaries began reflecting the 25 basis point adder for independent transmission ownership in transmission rates in November 2018. Refunds of $7 million were primarily made in the fourth quarter of 2018 and were completed in the first quarter of 2019. The MISO Regulated Operating Subsidiaries sought rehearing of the FERC’s October 18, 2018 order, and on July 18, 2019, the FERC denied the rehearing request. On September 11, 2019, the MISO Regulated Operating Subsidiaries filed an appeal of the FERC’s order in the D.C. Circuit Court. On December 16, 2019, the D.C. Circuit Court established a briefing schedule for the appeal. Initial briefs were filed on January 27, 2020 and reply briefs are due to be filed in the second quarter of 2020. We do not expect the final resolution of this proceeding to have a material adverse impact on our consolidated results of operations, cash flows or financial condition.
ITC Great Plains
On June 11, 2019, KCC filed a complaint with the FERC under section 206 of the FPA, challenging the ROE adder for independent transmission ownership that is included in the transmission rate charged by ITC Great Plains. The complaint argues that because ITC Great Plains is similarly situated to our MISO Regulated Operating Subsidiaries with respect to ownership by Fortis and GIC, the same rationale by which the FERC lowered the MISO Regulated Operating Subsidiaries adders for independent transmission ownership, as discussed above, also applies to ITC Great Plains. The adder for independent transmission ownership allows up to 100 basis points to be added to the ITC Great Plains authorized ROE, subject to any ROE cap established by the FERC. ITC Great Plains filed an answer to the complaint on July 1, 2019 asking the FERC to deny the complaint since KCC showed no evidence that ITC Great Plains’ independence or the benefits it provides as an independent TO has been compromised or reduced as a result of the Fortis and GIC acquisition. As of December 31, 2019, we had recorded an estimated current regulatory liability of $2 million related to this complaint. We do not expect the resolution of this proceeding to have a material adverse impact on our consolidated results of operations, cash flows or financial condition.


29

Significant Components of Results of Operations
Revenues
We derive nearly all of our revenues from providing transmission, scheduling, control and dispatch services and other related services over our Regulated Operating Subsidiaries’ transmission systems to DTE Electric, Consumers Energy, IP&L and other entities, such as alternative energy suppliers, power marketers and other wholesale customers that provide electricity to end-use consumers, as well as from transaction-based capacity reservations on our transmission systems. MISO and SPP are responsible for billing and collecting the majority of transmission service revenues. As the billing agent for our MISO Regulated Operating Subsidiaries and ITC Great Plains, MISO and SPP collect fees for the use of our transmission systems, invoicing DTE Electric, Consumers Energy, IP&L and other customers on a monthly basis.
Network Revenues are generated from network customers for their use of our electric transmission systems and are based on the actual revenue requirements as a result of our accounting under our cost-based Formula Rates that contain a true-up mechanism. Refer below under “— Critical Accounting Policies and Estimates — Revenue Recognition under Cost-Based Formula Rates with True-Up Mechanism” for a discussion of revenue recognition relating to network revenues.
Network revenues from ITC Great Plains include the annual revenue requirements specific to projects that are charged exclusively within one pricing zone within SPP or are classified as direct assigned network upgrades under the SPP tariff and contain a true-up mechanism.
Regional Cost Sharing Revenues are generated from transmission customers throughout RTO regions for their use of our MISO Regulated Operating Subsidiaries’ network upgrade projects that are eligible for regional cost sharing under provisions of the MISO tariff, including MVP projects such as our portion of four MVPs in the ITC Midwest footprint and the Thumb Loop Project in the Michigan footprint. Additionally, certain projects at ITC Great Plains are eligible for recovery through a region-wide charge under provisions of the SPP tariff. Regional cost sharing revenues is treated as a reduction to the net network revenue requirement under our cost-based Formula Rates.
Point-to-Point Revenues consist of revenues generated from a type of transmission service for which the customer pays for transmission capacity reserved along a specified path between two points on an hourly, daily, weekly or monthly basis. Point-to-point revenues also include other components pursuant to schedules under the MISO and SPP transmission tariffs. Point-to-point revenues are treated as a revenue credit to network or regional customers and are a reduction to gross revenue requirement when calculating net revenue requirement under our cost-based Formula Rates.
Scheduling, Control and Dispatch Revenues are allocated to our MISO Regulated Operating Subsidiaries by MISO as compensation for the services performed in operating the transmission system. Such services include monitoring of reliability data, current and next day analysis, implementation of emergency procedures and outage coordination and switching.
Other Revenues consist of rental revenues, easement revenues, revenues relating to utilization of jointly owned assets under our transmission ownership and operating agreements and amounts from providing ancillary services to customers. The majority of other revenues are treated as a revenue credit and taken as a reduction to gross revenue requirement when calculating net revenue requirement under our cost-based Formula Rates.
Operating Expenses
Operation and Maintenance Expenses consist primarily of the costs for contractors that operate and maintain our transmission systems as well as our personnel involved in operation and maintenance activities.
Operation expenses include activities related to control area operations, which involve balancing loads and generation and transmission system operations activities, including monitoring the status of our transmission lines and stations. Rental expenses relating to land easements, including METC’s Easement Agreement, are also recorded within operation expenses.
Maintenance expenses include preventive or planned maintenance, such as vegetation management, tower painting and equipment inspections, as well as reactive maintenance for equipment failures.


30

General and Administrative Expenses consist primarily of costs for personnel in our legal, information technology, finance, regulatory, human resources and business development organizations, general office expenses and fees for professional services. Professional services are principally composed of outside legal, consulting, audit and information technology services.
Depreciation and Amortization Expenses consist primarily of depreciation of property, plant and equipment using the straight-line method of accounting. Additionally, this consists of amortization of various regulatory and intangible assets.
Taxes Other than Income Taxes consist primarily of property taxes and payroll taxes.
Other Items of Income or Expense
Interest Expense consists primarily of interest on debt at ITC Holdings and our Regulated Operating Subsidiaries. Additionally, the amortization of debt financing expenses and loss on extinguishment of debt are recorded to interest expense. An allowance for borrowed funds used during construction is included in property, plant and equipment accounts and treated as a reduction to interest expense. The amortization of gains and losses on settled and terminated derivative financial instruments is recorded to interest expense. The interest portion of the refunds relating to the MISO ROE Complaints is also recorded to interest expense.
Allowance for Equity Funds Used During Construction (“AFUDC equity”) is recorded as an item of other income and is included in property, plant and equipment accounts. The allowance represents a return on equity at our Regulated Operating Subsidiaries used for construction purposes in accordance with the FERC regulations. The capitalization rate applied to the construction work in progress balance is based on the proportion of equity to total capital (which currently includes equity and long-term debt) and the allowed return on equity for our Regulated Operating Subsidiaries.
Income Tax Provision
Income tax provision consists of current and deferred federal and state income taxes.
Results of Operations
The following table summarizes historical operating results for the periods indicated:
 
Year Ended
 
 
 
Percentage
 
Year Ended
 
 
 
Percentage
 
December 31,
 
Increase
 
Increase
 
December 31,
 
Increase
 
Increase
(In millions)
2019
 
2018
 
(Decrease)
 
(Decrease)
 
2017
 
(Decrease)
 
(Decrease)
OPERATING REVENUES
 
 
 
 
 
 
 
 
 
 
 
 
 
Transmission and other services
$
1,286

 
$
1,192

 
$
94

 
8
 %
 
$
1,226

 
$
(34
)
 
(3
)%
Formula Rate true-up
41

 
(36
)
 
77

 
(214
)%
 
(15
)
 
(21
)
 
140
 %
Total operating revenue
1,327

 
1,156

 
171

 
15
 %
 
1,211

 
(55
)
 
(5
)%
OPERATING EXPENSES
 
 
 
 
 
 
 
 
 
 
 
 
 
Operation and maintenance
113

 
109

 
4

 
4
 %
 
110

 
(1
)
 
(1
)%
General and administrative
138

 
127

 
11

 
9
 %
 
121

 
6

 
5
 %
Depreciation and amortization
203

 
180

 
23

 
13
 %
 
169

 
11

 
7
 %
Taxes other than income taxes
118

 
109

 
9

 
8
 %
 
103

 
6

 
6
 %
Other operating (income) and expenses, net
—

 
(4
)
 
4

 
(100
)%
 
(2
)
 
(2
)
 
100
 %
Total operating expenses
572

 
521

 
51

 
10
 %
 
501

 
20

 
4
 %
OPERATING INCOME
755

 
635

 
120

 
19
 %
 
710

 
(75
)
 
(11
)%
OTHER EXPENSES (INCOME)
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest expense, net
224

 
224

 
—

 
—
 %
 
224

 
—

 
—
 %
Allowance for equity funds used during construction
(29
)
 
(33
)
 
4

 
(12
)%
 
(33
)
 
—

 
—
 %
Other (income) and expenses, net
—

 
3

 
(3
)
 
(100
)%
 
4

 
(1
)
 
(25
)%
Total other expenses (income)
195

 
194

 
1

 
1
 %
 
195

 
(1
)
 
(1
)%
INCOME BEFORE INCOME TAXES
560

 
441

 
119

 
27
 %
 
515

 
(74
)
 
(14
)%
INCOME TAX PROVISION
132

 
111

 
21

 
19
 %
 
196

 
(85
)
 
(43
)%
NET INCOME
$
428

 
$
330

 
$
98

 
30
 %
 
$
319

 
$
11

 
3
 %


31

Operating Revenues
Year ended December 31, 2019 compared to year ended December 31, 2018
The following table sets forth the components of and changes in operating revenues for the year ended December 31, 2019 and 2018 which included revenue accruals and deferrals in Note 6 to the consolidated financial statements:
 
 
 
 
 
 
 
 
 
 
 
Percentage
 
2019
 
2018
 
Increase
 
Increase
(In millions)
Amount
 
Percentage
 
Amount
 
Percentage
 
(Decrease)
 
(Decrease)
Network revenues (a)
$
836

 
63
%
 
$
771

 
67
%
 
$
65

 
8
 %
Regional cost sharing revenues (a)
371

 
28
%
 
334

 
29
%
 
37

 
11
 %
Point-to-point
13

 
1
%
 
14

 
1
%
 
(1
)
 
(7
)%
Scheduling, control and dispatch (a)
17

 
1
%
 
15

 
1
%
 
2

 
13
 %
Other
21

 
2
%
 
21

 
2
%
 
—

 
—
 %
Recognition of liabilities for MISO ROE Complaints
69

 
5
%
 
1

 
—
%
 
68

 
6,800
 %
Total
$
1,327

 
100
%
 
$
1,156

 
100
%
 
$
171

 
15
 %
____________________________
(a)
Includes a portion of the Formula Rate true-up of $41 million and $(36) million for the year ended December 31, 2019 and 2018, respectively.
Network revenues increased primarily due to higher net network revenue requirements at our Regulated Operating Subsidiaries, partially offset by an increase in revenue credits resulting from higher regional cost sharing revenue requirements, during the year ended December 31, 2019 compared to the same period in 2018. Higher net network revenue requirements were due primarily to a higher rate base associated with higher balances of property, plant and equipment in service.
Regional cost sharing revenues increased primarily due to additional capital projects eligible for regional cost sharing and these projects being placed into service, in addition to higher accumulated investment for existing regional cost sharing projects for the year ended December 31, 2019 compared to the same period in 2018.
During the year ended December 31, 2019, adjustments were made to the refund liability recorded related to the MISO ROE Complaints, as described in Note 19 to the consolidated financial statements, which resulted in a net increase in operating revenues of $69 million for the year ended December 31, 2019 compared to the same period in 2018. As a result of the November 2019 Order, operating revenues increased $133 million due to the dismissal of the Second Complaint, which was partially offset by a revenue decrease of $64 million for the establishment of an additional refund liability for the Initial Complaint and the period from the date of the September 2016 Order to December 31, 2019.
Operating Expenses
General and administrative expenses
Year ended December 31, 2019 compared to year ended December 31, 2018
General and administrative expenses increased primarily due to higher compensation-related expenses resulting from additional share-based compensation expense of $23 million. This increase was partially offset by lower professional services, such as legal and advisory service fees, related to various development initiatives of $15 million.
Depreciation and amortization expenses
Year ended December 31, 2019 compared to year ended December 31, 2018
Depreciation and amortization expenses increased primarily due to a higher depreciable base resulting from property, plant and equipment in-service additions.


32

Taxes other than income taxes
Year ended December 31, 2019 compared to year ended December 31, 2018
Taxes other than income taxes increased due to higher property tax expenses primarily due to our Regulated Operating Subsidiaries’ 2018 capital additions, which were included in the assessments for 2019 property taxes.
Other Expenses (Income)
Interest Expense, Net
Year ended December 31, 2019 compared to year ended December 31, 2018
Interest expense, net remained consistent due to higher debt balances offset by the reversal of interest expense previously recorded for the Second Complaint pursuant to the November 2019 Order, as described in Note 19 to the consolidated financial statements.
Income Tax Provision
Year ended December 31, 2019 compared to year ended December 31, 2018
Our effective tax rates for the years ended December 31, 2019 and 2018 were 23.6% and 25.2%, respectively. Our effective tax rate as of December 31, 2019 exceeded our 21% statutory federal income tax rate primarily due to state income taxes, partially offset by AFUDC equity. During the year ended December 31, 2018, Iowa enacted a reduction in corporate statutory income tax rates from 12.0% to 9.8%, effective January 1, 2021. Based upon the future change in Iowa’s tax rate, we revalued the Iowa NOLs at ITC Holdings in 2018. As a result, additional income tax expense was recorded for the year ended December 31, 2018 compared to the same period in 2019. The amount of income tax expense relating to AFUDC equity was recognized as a regulatory asset and is not included in the income tax provision. See Note 12 to the consolidated financial statements for further discussion regarding our income tax provision.
Liquidity and Capital Resources
We expect to maintain our approach of funding our future capital requirements with cash from operations at our Regulated Operating Subsidiaries, our existing cash and cash equivalents, future issuances under our commercial paper program and amounts available under our revolving and term loan credit agreements (the terms of which are described in Note 11 to the consolidated financial statements). In addition, we may from time to time secure debt funding in the capital markets, although we can provide no assurance that we will be able to obtain financing on favorable terms or at all. As market conditions warrant, we may also from time to time repurchase debt securities issued by us, in the open market, in privately negotiated transactions, by tender offer or otherwise. We expect that our capital requirements will arise principally from our need to:
•
Fund capital expenditures at our Regulated Operating Subsidiaries. Our plans with regard to property, plant and equipment investments are described in detail above under “— Capital Investment and Operating Results Trends.”
•
Fund business development expenses and related capital expenditures. We are pursuing development activities for projects that could result in significant development expenses and capital expenditures incremental to our current plan. Refer to Note 19 to the consolidated financial statements for a discussion of contingent payments related to development projects.
•
Fund working capital requirements.
•
Fund our debt service requirements, including principal repayments and periodic interest payments, which are further described in detail below under “— Contractual Obligations.”
•
Fund any refund obligation in connection with the pending ROE matters.
In addition to the expected capital requirements above, any adverse determinations or settlements relating to the regulatory matters or contingencies described in Notes 6 and 19 to the consolidated financial statements would result in additional capital requirements.
We believe that we have sufficient capital resources to meet our currently anticipated short-term needs. We rely on both internal and external sources of liquidity to provide working capital and fund capital investments. ITC Holdings’ sources of cash are dividends and other payments received by us from our Regulated Operating


33

Subsidiaries and any of our other subsidiaries as well as the proceeds raised from the sale of our debt securities. Each of our Regulated Operating Subsidiaries, while wholly owned by ITC Holdings, is legally distinct from ITC Holdings and has no obligation, contingent or otherwise, to make funds available to us.
We expect to continue to utilize our commercial paper program and revolving and term loan credit agreements as well as our cash and cash equivalents as needed to meet our short-term cash requirements. As of December 31, 2019, we had consolidated indebtedness under our revolving and term loan credit agreements of $499 million, with unused capacity under our revolving credit agreements of $601 million and unused capacity under our term loan credit agreement of $200 million. In January 2020, ITC Holdings drew upon the remaining $200 million under the term loan credit agreement, which was used to repay outstanding commercial paper balances. ITC Holdings had $200 million of commercial paper issued and outstanding, net of discount, as of December 31, 2019, with the ability to issue an additional $200 million under the commercial paper program. See Note 11 to the consolidated financial statements for a detailed discussion of the commercial paper program, our revolving and term loan credit agreements and other debt activity during the years ended December 31, 2019 and 2018.
To address our long-term capital requirements, we expect that we will need to obtain additional debt financing. Certain of our capital projects could be delayed if we experience difficulties in accessing capital. We expect to be able to obtain such additional financing as needed, in amounts and upon terms that will be reasonably satisfactory to us due to our strong credit ratings and our historical ability to obtain financing.
We have material exposure to LIBOR through the revolving credit agreements of ITC Holdings and certain of our Regulated Operating Subsidiaries. It is expected that LIBOR will be discontinued and, while we believe an acceptable replacement rate will be available if LIBOR is discontinued, we cannot reasonably estimate the expected impact, if any, of such a discontinuation.
Credit Ratings
Credit ratings by nationally recognized statistical rating agencies are an important component of our liquidity profile. Credit ratings relate to our ability to issue debt securities and the cost to borrow money and should not be viewed as a recommendation to buy, sell or hold securities. Ratings are subject to revision or withdrawal at any time and each rating should be evaluated independently of any other rating. Our current credit ratings are displayed in the following table. An explanation of these ratings may be obtained from the respective rating agency.
 
 
S&P (a)
 
Moody’s
 
 
Rating
 
Outlook
 
Rating
 
Outlook
ITC Holdings
 
 
 
 
 
 
 
 
 Senior Unsecured Notes
 
BBB+
 
Negative
 
Baa2
 
Stable
 Commercial Paper
 
A-2
 
Negative
 
Prime-2
 
Stable
ITCTransmission
 
 
 
 
 
 
 
 
 First Mortgage Bonds
 
A
 
Negative
 
A1
 
Stable
METC
 
 
 
 
 
 
 
 
 Senior Secured Notes
 
A
 
Negative
 
A1
 
Stable
ITC Midwest
 
 
 
 
 
 
 
 
 First Mortgage Bonds
 
A
 
Negative
 
A1
 
Stable
ITC Great Plains
 
 
 
 
 
 
 
 
 First Mortgage Bonds
 
A
 
Negative
 
A1
 
Stable
____________________________
(a)
On September 26, 2019, S&P revised the ratings of senior unsecured notes at ITC Holdings from A- to BBB+, reflecting expected increases in the ratio of debt at our Regulated Operating Subsidiaries relative to amounts at ITC Holdings. All other ratings were reaffirmed and the outlook remains unchanged.
Covenants
Our debt instruments contain numerous financial and operating covenants that place significant restrictions on certain transactions, such as incurring additional indebtedness, engaging in sale and lease-back transactions, creating liens or other encumbrances, entering into mergers, consolidations, liquidations or dissolutions, creating or acquiring subsidiaries and selling or otherwise disposing of all or substantially all of our assets. In addition, the


34

covenants require us to meet certain financial ratios, such as maintaining certain debt to capitalization ratios and certain funds from operations to debt levels. As of December 31, 2019, we were not in violation of any debt covenant. In the event of a downgrade in our credit ratings, none of the covenants would be directly impacted, although the borrowing costs under our revolving credit agreements may increase.
Cash Flows
The following table summarizes cash flows for the periods indicated:
 
Year Ended December 31,
(In millions)
2019
 
2018
 
2017
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
 
 
Net income
$
428

 
$
330

 
$
319

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
 
Depreciation and amortization expense
203

 
180

 
169

Recognition, refund and collection of revenue accruals and deferrals — including accrued interest
(55
)
 
17

 
34

Deferred income tax expense
135

 
107

 
195

Other
(82
)
 
19

 
(110
)
Net cash provided by operating activities
629

 
653

 
607

CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
 
 
Expenditures for property, plant and equipment
(865
)
 
(769
)
 
(755
)
Contributions in aid of construction
10

 
21

 
21

Other
1

 
1

 
(10
)
Net cash used in investing activities
(854
)
 
(747
)
 
(744
)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
 
 
Net issuance/repayment of debt (including commercial paper and revolving and term loan credit agreements)
463

 
238

 
511

Dividends to ITC Investment Holdings
(250
)
 
(200
)
 
(300
)
Refundable deposits from and repayments to generators for transmission network upgrades, net
11

 
3

 
(12
)
Other
(3
)
 
(5
)
 
(5
)
Net cash provided by financing activities
221

 
36

 
194

NET (DECREASE) INCREASE IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH
(4
)
 
(58
)
 
57

CASH, CASH EQUIVALENTS AND RESTRICTED CASH — Beginning of period
10

 
68

 
11

CASH, CASH EQUIVALENTS AND RESTRICTED CASH — End of period
$
6

 
$
10

 
$
68

Cash Flows From Operating Activities
Year ended December 31, 2019 compared to year ended December 31, 2018
Net cash provided by operating activities was $629 million and $653 million for the year ended December 31, 2019 and 2018, respectively. The decrease in cash provided by operating activities was due primarily to lower tax refunds received of $12 million, higher interest payments of $5 million and higher property tax payments of $7 million during the year ended December 31, 2019 compared to the same period in 2018.
Cash Flows From Investing Activities
Year ended December 31, 2019 compared to year ended December 31, 2018
Net cash used in investing activities was $854 million and $747 million for the year ended December 31, 2019 and 2018, respectively. The increase in cash used in investing activities was primarily due to an increase in capital expenditures of $96 million, including the electric transmission asset acquisition of $76 million from Consumer’s Energy, and a decrease in contributions received in aid of construction of $11 million during the year ended December 31, 2019 compared to the same period in 2018.


35

Cash Flows From Financing Activities
Year ended December 31, 2019 compared to year ended December 31, 2018
Net cash provided by financing activities was $221 million and $36 million for the year ended December 31, 2019 and 2018, respectively. The increase in cash provided by financing activities was due primarily to an increase in net borrowings under our revolving and term loan credit agreements of $353 million and an increase in net issuances of commercial paper of $200 million during the year ended December 31, 2019 compared to the same period in 2018. These increases were partially offset by a decrease in issuances of long-term debt of $225 million, an increase in retirement of long-term debt of $103 million and an increase in dividend payments of $50 million during the year ended December 31, 2019 compared to the same period in 2018. See Note 11 to the consolidated financial statements for detail on the issuances and retirements of debt, borrowings under our term loan credit agreement and a description of our revolving credit agreements and commercial paper program.
Contractual Obligations
The following table details our contractual obligations as of December 31, 2019:
 
 
 
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
$
2,550

 
$
—

 
$
500

 
$
650

 
$
1,400

ITC Holdings revolving credit agreement (a)
34

 
—

 
34

 
—

 
—

ITC Holdings commercial paper program
200

 
200

 
—

 
—

 
—

ITC Holdings term loan credit agreement
200

 
—

 
200

 
—

 
—

ITCTransmission First Mortgage Bonds
785

 
—

 
—

 
—

 
785

ITCTransmission revolving credit agreement (a)
24

 
—

 
24

 
—

 
—

METC Senior Secured Notes
575

 
—

 
—

 
—

 
575

METC revolving credit agreement (a)
79

 
—

 
79

 
—

 
—

ITC Midwest First Mortgage Bonds
1,085

 
35

 
—

 
75

 
975

ITC Midwest revolving credit agreement (a)
130

 
—

 
130

 
—

 
—

ITC Great Plains First Mortgage Bonds
150

 
—

 
—

 
—

 
150

ITC Great Plains revolving credit agreement (a)
32

 
—

 
32

 
—

 
—

Interest payments:
 
 
 
 
 
 
 
 
 
ITC Holdings Senior Notes
944

 
97

 
192

 
143

 
512

ITCTransmission First Mortgage Bonds
888

 
35

 
70

 
70

 
713

METC Senior Secured Notes
622

 
24

 
49

 
49

 
500

ITC Midwest First Mortgage Bonds
1,106

 
49

 
93

 
92

 
872

ITC Great Plains First Mortgage Bonds
155

 
6

 
12

 
12

 
125

Operating leases
4

 
1

 
2

 
1

 
—

Purchase obligations
77

 
74

 
1

 
1

 
1

Regulatory liabilities — revenue deferrals, including accrued interest
52

 
51

 
1

 
—

 
—

Regulatory liabilities — refund related to the MISO ROE Complaints, including accrued interest (b)
70

 
70

 
—

 
—

 
—

METC Easement Agreement
309

 
10

 
20

 
20

 
259

Total obligations
$
10,071

 
$
652

 
$
1,439

 
$
1,113

 
$
6,867

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


36

(b)
Amount reflects terms outlined in the November 2019 Order related to the MISO ROE Complaints, as described in Note 19 to the consolidated financial statements.
Interest payments included above relate only to our fixed-rate long-term debt outstanding at December 31, 2019. We also expect to pay interest and commitment fees under our variable-rate revolving and term loan credit agreements and commercial paper program that have not been included above due to varying amounts of borrowings and interest rates under the facilities. In 2019, we paid $16 million of interest and commitment fees under our revolving and term loan credit agreements and commercial paper program.
Operating leases include leases for office space, equipment and storage facilities. Purchase obligations represent commitments primarily for materials, services and equipment that had not been received as of December 31, 2019, primarily for construction and maintenance projects for which we have an executed contract. The majority of the items relate to materials and equipment that have long production lead times. See Note 10 and Note 19 to the consolidated financial statements for more information on our operating leases and purchase obligations, respectively.
The revenue deferrals, including accrued interest, in the table above represent the over-recovery of revenues resulting from differences between the amounts billed to customers and actual revenue requirement at each of our Regulated Operating Subsidiaries, as described in Note 6 to the consolidated financial statements. These amounts will offset future revenue requirement for purposes of calculating our Formula Rates as part of the true-up mechanism in our rate construct.
The Easement Agreement provides METC with an easement for transmission purposes and rights-of-way, leasehold interests, fee interests and licenses associated with the land over which the transmission lines cross. The cost for use of the rights-of-way is $10 million per year. The term of the Easement Agreement runs through December 31, 2050 and is subject to 10 automatic 50-year renewals thereafter unless METC gives notice of nonrenewal of at least one year in advance. Payments to Consumers Energy under the Easement Agreement are charged to operation and maintenance expense.
The contractual obligations table above excludes certain items, including contingent liabilities and other current and long-term liabilities, due to uncertainty regarding the timing and any amount of future cash flows necessary to settle these obligations. Items excluded from the contractual obligations table include:
•
long-term incentive awards;
•
pension and other postretirement obligations;
•
regulatory liabilities related to asset removal costs and income taxes refundable related to implementation of the TCJA; and
•
liabilities to refund deposits from generators for transmission network upgrades.
Critical Accounting Policies and Estimates
Our consolidated financial statements are prepared in accordance with GAAP. The preparation of these consolidated financial statements requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. The application of these policies requires judgments regarding future events.
These estimates and judgments, in and of themselves, could materially impact the consolidated financial statements and disclosures based on varying assumptions, as future events rarely develop exactly as forecasted, and even the best estimates routinely require adjustment.
The following is a list of accounting policies that are most significant to the portrayal of our financial condition and results of operations and/or that require management’s most difficult, subjective or complex judgments.
Regulation
Our Regulated Operating Subsidiaries are subject to rate regulation by the FERC. As a result, we apply accounting principles in accordance with the standards set forth by the FASB for accounting for the effects of certain types of regulation. Use of this accounting guidance results in differences in the application of GAAP between regulated and non-regulated businesses and requires the recording of regulatory assets and liabilities for certain transactions that would have been treated as expense or revenue in non-regulated businesses. As described in Note 7 to the consolidated financial statements, we had regulatory assets and liabilities of $241 million


37

and $707 million, respectively, as of December 31, 2019. Future changes in the regulatory and competitive environments could result in discontinuing the application of the accounting standards for the effects of certain types of regulations. If we were to discontinue the application of this guidance on the operations of our Regulated Operating Subsidiaries, we may be required to record losses relating to certain regulatory assets or gains relating to certain regulatory liabilities. We also may be required to record losses of $33 million relating to intangible assets at December 31, 2019 that are described in Note 9 to the consolidated financial statements.
We believe that currently available facts support the continued applicability of the standards for accounting for the effects of certain types of regulation and that all regulatory assets and liabilities are recoverable or refundable under our current rate environment.
Revenue Recognition under Cost-Based Formula Rates with True-Up Mechanism
Our Regulated Operating Subsidiaries recover expenses and earn a return on and recover investments in property, plant and equipment on a current basis, under their forward-looking cost-based Formula Rates with a true-up mechanism.
Under their Formula Rates, our Regulated Operating Subsidiaries use forecasted expenses, property, plant and equipment, point-to-point revenues and other items for the upcoming calendar year to establish their projected revenue requirement and for the MISO Regulated Operating Subsidiaries, their component of the billed network rates for service on their systems from January 1 to December 31 of that year. The cost-based Formula Rates include a true-up mechanism, whereby our Regulated Operating Subsidiaries compare their actual revenue requirements to their billed revenues for each year to subsequently collect or refund any over-recovery or under-recovery of revenues, as appropriate. The over- or under-collection typically results from differences between the projected revenue requirement used as the basis for billing and actual revenue requirement at each of our Regulated Operating Subsidiaries, or from differences between actual and projected monthly peak loads at our MISO Regulated Operating Subsidiaries.
The true-up mechanisms under our Formula Rates meet the GAAP requirements for accounting for rate-regulated utilities and the effects of certain alternative revenue programs. Accordingly, revenue is recognized during each reporting period based on actual revenue requirements calculated using the cost-based Formula Rates. Our Regulated Operating Subsidiaries accrue or defer revenues to the extent that their actual revenue requirement for the reporting period is higher or lower, respectively, than the amounts billed relating to that reporting period. The true-up amount is automatically reflected in customer bills within two years under the provisions of the Formula Rates. See Note 7 to the consolidated financial statements for the regulatory assets and liabilities recorded at our Regulated Operating Subsidiaries’ as a result of the Formula Rate revenue accruals and deferrals.
Valuation of Goodwill
We have goodwill resulting from our acquisitions of ITCTransmission and METC and ITC Midwest’s acquisition of the IP&L transmission assets. We perform an impairment test annually at the reporting unit level or whenever events or circumstances indicate that the value of goodwill may be impaired. Our reporting units are ITCTransmission, METC and ITC Midwest as each entity represents an individual operating segment to which goodwill has been assigned. In order to perform an impairment assessment, we have the option of performing a qualitative assessment to determine whether the existence of events or circumstances leads to a determination that it is more likely than not that the fair value of a reporting unit is greater than its carrying amount. In performing a qualitative assessment, we assess macroeconomic conditions, industry and market considerations, cost factors, overall financial performance, entity-specific considerations, and industry-specific considerations such as our regulatory environment and rate structure. If, after assessing the totality of events or circumstances, we determine it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, then performing a quantitative impairment analysis is unnecessary.
If we determine a quantitative analysis is necessary or we elect to bypass the qualitative assessment, we compare the fair value of each reporting unit with their respective carrying value. We determine fair value using valuation techniques based on discounted future cash flows under various scenarios. We also consider estimates of market-based valuation multiples for companies within the peer group of our reporting units. The market-based multiples involve judgment regarding the appropriate peer group and the appropriate multiple to apply in the valuation and the cash flow estimates involve judgments based on a broad range of assumptions, information and historical results. To the extent estimated market-based valuation multiples and/or discounted cash flows are


38

revised downward, we may be required to write down all or a portion of goodwill, which would adversely impact earnings.
As of December 31, 2019 and 2018, consolidated goodwill totaled $950 million. We completed our annual goodwill impairment test for our reporting units as of October 1, 2019 using a qualitative assessment and determined that no impairment exists. There were no events subsequent to October 1, 2019 that indicated impairment of our goodwill. We do not believe there is a material risk of our goodwill being impaired in the near term for any of our reporting units.
Contingent Obligations
We are subject to a number of federal and state laws and regulations, as well as other factors and conditions that potentially subject us to environmental, litigation, income tax and other contingencies. Additionally, we have other contingent obligations that may be required to be paid to developers based on achieving certain milestones relating to development initiatives. We periodically evaluate our exposure to such contingencies and record liabilities for those matters where a loss is considered probable and reasonably estimable. Our liabilities exclude any estimates for legal costs not yet incurred associated with handling these matters, which could be material. The adequacy of liabilities recorded can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect our consolidated financial statements. These events or conditions include, without limitation, the following:
•
Changes in existing state or federal regulation by governmental authorities having jurisdiction over air quality, water quality, control of toxic substances, hazardous and solid wastes and other environmental matters.
•
Changes in existing federal income tax laws or IRS regulations.
•
Identification and evaluation of lawsuits or complaints in which we may be or have been named as a defendant.
•
Resolution or progression of existing matters through the legislative process, the courts, the FERC, the NERC, the IRS or the Environmental Protection Agency.
•
Completion of certain milestones relating to development initiatives.
Refer to Note 19 to the consolidated financial statements for discussion on contingencies, including the MISO ROE Complaints.
Pension and Postretirement Costs
We sponsor certain retirement benefits for our employees, which include retirement pension plans and certain postretirement health care, dental and life insurance benefits. Our periodic costs and obligations associated with these plans are developed from actuarial valuations derived from a number of assumptions, including rates of return on plan assets, the discount rates, the rate of increase in health care costs, the amount and timing of plan sponsor contributions and demographic factors such as retirements, mortality and turnover, among others. We evaluate these assumptions annually and update them periodically to reflect our actual experience. Three critical assumptions in determining our periodic costs and obligations are discount rate, expected long-term return on plan assets and the rate of increases in health care costs. The discount rate represents the market rate for synthesized AA-rated zero-coupon bonds with durations corresponding to the expected durations of the benefit obligations and is used to calculate the present value of the expected future cash flows for benefit obligations under our plans. In determining our long-term rate of return on plan assets, we consider the current and expected asset allocations, as well as historical and expected long-term rates of return on those types of asset classes. Assumed health care cost trend rates may have a significant effect on the amounts reported for the health care plans.
Off-Balance Sheet Arrangements
We have no off-balance sheet arrangements that have or are reasonably likely to have a material effect on our financial condition.
Recent Accounting Pronouncements
See Note 2 to the consolidated financial statements.


39

ITEM 7A.     QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Commodity Price Risk
We have commodity price risk at our Regulated Operating Subsidiaries arising from market price fluctuations for materials such as copper, aluminum, steel, oil and gas and other goods used in construction and maintenance activities. Higher costs of these materials are passed on to us by the contractors for these activities. These items affect only cash flows, as the amounts are included as components of net revenue requirement and any higher costs are included in rates under their cost-based Formula Rates.
Interest Rate Risk
Fixed Rate Debt
Based on the borrowing rates currently available for bank loans with similar terms and average maturities, the fair value of our consolidated long-term debt and debt maturing within one year, excluding revolving and term loan credit agreements and commercial paper, was $5,672 million at December 31, 2019. The total book value of our consolidated long-term debt and debt maturing within one year, net of discount and deferred financing fees and excluding revolving and term loan credit agreements and commercial paper, was $5,108 million at December 31, 2019. We performed an analysis calculating the impact of changes in interest rates on the fair value of long-term debt and debt maturing within one year, excluding revolving and term loan credit agreements and commercial paper at December 31, 2019. An increase in interest rates of 10% (from 5.0% to 5.5%, for example) at December 31, 2019 would decrease the fair value of debt by $210 million, and a decrease in interest rates of 10% at December 31, 2019 would increase the fair value of debt by $226 million at that date.
Revolving and Term Loan Credit Agreements
At December 31, 2019, we had a consolidated total of $499 million outstanding under our revolving and term loan credit agreements, which are variable rate loans and fair value approximates book value. A 10% increase or decrease in borrowing rates under the revolving and term loan credit agreements compared to the weighted average rates in effect at December 31, 2019 would increase or decrease interest expense by $1 million for an annual period with a constant borrowing level of $499 million.
Commercial Paper
At December 31, 2019, ITC Holdings had $200 million of commercial paper issued and outstanding, net of discount, under the commercial paper program. Due to the short-term nature of these financial instruments, the carrying value approximates fair value. A 10% increase or decrease in interest rates for commercial paper would increase or decrease interest expense by less than $1 million for an annual period with a continuous level of commercial paper outstanding of $200 million.
Derivative Instruments and Hedging Activities
We use derivative financial instruments, including interest rate swap contracts, to manage our exposure to fluctuations in interest rates. The use of these financial instruments mitigates exposure to these risks and the variability of our operating results. We are not a party to leveraged derivatives and do not enter into derivative financial instruments for trading or speculative purposes.
As of December 31, 2019, we held 5-year interest rate swap contracts with a notional amount of $200 million, which manage interest rate risk associated with the refinancing of the $400 million term loan at ITC Holdings with a maturity date of June 11, 2021. As of December 31, 2019, ITC Holdings had $200 million outstanding under the term loan credit agreement. In January 2020, ITC Holdings drew upon the remaining $200 million under the term loan credit agreement. In January 2020, ITC Holdings entered into three 5-year interest rate swap contracts with notional amounts of $63 million. See Note 11 to the consolidated financial statements for further discussion on these interest rate swaps.
Credit Risk
Our credit risk is primarily with DTE Electric, Consumers Energy and IP&L, which were responsible for approximately 21.1%, 23.2% and 24.8%, respectively, or $254 million, $279 million and $298 million, respectively, of our consolidated billed revenues for the year ended December 31, 2019. These percentages and amounts of total billed revenues of DTE Electric, Consumers Energy and IP&L include the collection of 2017 revenue accruals and deferrals and exclude any amounts for the 2019 revenue accruals and deferrals that were included in our


40

2019 operating revenues but will not be billed to our customers until 2021. Refer to “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cost-Based Formula Rates with True-Up Mechanism” for a discussion on the difference between billed revenues and operating revenues. Under DTE Electric’s and Consumers Energy’s current rate structure, DTE Electric and Consumers Energy include in their retail rates the actual cost of transmission services provided by ITCTransmission and METC, respectively, in their billings to their customers, effectively passing through to end-use consumers the total cost of transmission service. IP&L currently includes in their retail rates an allowance for transmission services provided by ITC Midwest in their billings to their customers. However, any financial difficulties experienced by DTE Electric, Consumers Energy or IP&L may affect their ability to make payments for transmission service to ITCTransmission, METC, and ITC Midwest, which could negatively impact our business. MISO, as our MISO Regulated Operating Subsidiaries’ billing agent, bills DTE Electric, Consumers Energy, IP&L and other customers on a monthly basis and collects fees for the use of the MISO Regulated Operating Subsidiaries’ transmission systems. SPP is the billing agent for ITC Great Plains and bills transmission customers for the use of ITC Great Plains transmission systems. MISO and SPP have implemented strict credit policies for its members’ customers, which include customers using our transmission systems. Specifically, MISO and SPP require a letter of credit or cash deposit equal to the credit exposure, which is determined by a credit scoring model and other factors, from any customer using a member’s transmission system.


41

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
 
43
Report of Independent Registered Public Accounting Firm
 
44
Consolidated Statements of Financial Position as of December 31, 2019 and 2018
 
45
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2019, 2018 and 2017
 
46
Consolidated Statements of Changes in Stockholder’s Equity for the Years Ended December 31, 2019, 2018 and 2017
 
47
Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 2018 and 2017
 
48
Notes to Consolidated Financial Statements
 
49
Schedule I — Condensed Financial Information of Registrant
 
129



42

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is designed to provide reasonable, not absolute, assurance as to the reliability of our financial reporting and the preparation of financial statements in accordance with generally accepted accounting principles. Internal control over financial reporting, no matter how well designed, has inherent limitations. Therefore, internal control over financial reporting determined to be effective can provide only reasonable assurance with respect to financial statement preparation and may not prevent or detect all misstatements.
Under management’s supervision, an evaluation of the design and effectiveness of our internal control over financial reporting was conducted based on the criteria set forth in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Our assessment included documenting, evaluating and testing of the design and operating effectiveness of our internal control over financial reporting. Based on this evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2019.


43

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


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

Opinion on the Financial Statements

We have audited the accompanying consolidated statements of financial position of ITC Holdings Corp. and subsidiaries (the "Company") as of December 31, 2019 and 2018, the related consolidated statements of comprehensive income, changes in stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2019, and the related notes and the schedule listed in the Index at Item 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material aspects, the financial condition of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

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

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


/s/ DELOITTE & TOUCHE LLP
Detroit, Michigan
February 12, 2020

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


44

ITC HOLDINGS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
 
December 31,
(In millions, except share data)
2019
 
2018
ASSETS
Current assets
 
 
 
Cash and cash equivalents
$
4

 
$
6

Accounts receivable
117

 
102

Inventory
39

 
32

Regulatory assets
12

 
12

Income tax receivable
—

 
1

Prepaid and other current assets
15

 
11

Total current assets
187

 
164

Property, plant and equipment (net of accumulated depreciation and amortization of $1,930 and $1,779, respectively)
8,582

 
7,910

Other assets
 
 
 
Goodwill
950

 
950

Intangible assets (net of accumulated amortization of $42 and $39, respectively)
33

 
38

Regulatory assets
229

 
200

Other assets
77

 
67

Total other assets
1,289

 
1,255

TOTAL ASSETS
$
10,058

 
$
9,329

LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities
 
 
 
Accounts payable
$
82

 
$
106

Accrued compensation
61

 
30

Accrued interest
48

 
50

Accrued taxes
66

 
64

Regulatory liabilities
123

 
178

Refundable deposits and advances for construction
27

 
33

Debt maturing within one year
235

 
—

Other current liabilities
16

 
11

Total current liabilities
658

 
472

Accrued pension and postretirement liabilities
73

 
68

Deferred income taxes
873

 
721

Regulatory liabilities
584

 
640

Refundable deposits
19

 
13

Other liabilities
47

 
26

Long-term debt
5,572

 
5,338

Commitments and contingent liabilities (Notes 6 and 19)


 


STOCKHOLDER’S EQUITY
 
 
 
Common stock, without par value, 235,000,000 shares authorized, 224,203,112 shares issued and outstanding at December 31, 2019 and 2018
892

 
892

Retained earnings
1,333

 
1,155

Accumulated other comprehensive income
7

 
4

Total stockholder’s equity
2,232

 
2,051

TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY
$
10,058

 
$
9,329

See notes to consolidated financial statements.


45

ITC HOLDINGS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 
Year Ended December 31,
(In millions)
2019
 
2018
 
2017
OPERATING REVENUES
 
 
 
 
 
Transmission and other services
$
1,286

 
$
1,192

 
$
1,226

Formula Rate true-up
41

 
(36
)
 
(15
)
Total operating revenue
1,327

 
1,156

 
1,211

OPERATING EXPENSES
 
 
 
 
 
Operation and maintenance
113

 
109

 
110

General and administrative
138

 
127

 
121

Depreciation and amortization
203

 
180

 
169

Taxes other than income taxes
118

 
109

 
103

Other operating (income) and expense, net
—

 
(4
)
 
(2
)
Total operating expenses
572

 
521

 
501

OPERATING INCOME
755

 
635

 
710

OTHER EXPENSES (INCOME)
 
 
 
 
 
Interest expense, net
224

 
224

 
224

Allowance for equity funds used during construction
(29
)
 
(33
)
 
(33
)
Other (income) and expenses, net
—

 
3

 
4

Total other expenses (income)
195

 
194

 
195

INCOME BEFORE INCOME TAXES
560

 
441

 
515

INCOME TAX PROVISION
132

 
111

 
196

NET INCOME
428

 
330

 
319

OTHER COMPREHENSIVE INCOME (LOSS)
 
 
 
 
 
Derivative instruments, net of tax (Note 15)
3

 
1

 
—

TOTAL OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
3

 
1

 
—

TOTAL COMPREHENSIVE INCOME
$
431

 
$
331

 
$
319

See notes to consolidated financial statements.


46

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, 2016
$
892

 
$
1,007

 
$
2

 
$
1,901

Net income
—

 
319

 
—

 
319

Dividends to ITC Investment Holdings
—

 
(300
)
 
—

 
(300
)
BALANCE, DECEMBER 31, 2017
$
892

 
$
1,026

 
$
2

 
$
1,920

Opening balance reclassification
—

 
(1
)
 
1

 
—

Net income
—

 
330

 
—

 
330

Dividends to ITC Investment Holdings
—

 
(200
)
 
—

 
(200
)
Other comprehensive income, net of tax (Note 15)
—

 
—

 
1

 
1

BALANCE, DECEMBER 31, 2018
$
892

 
$
1,155

 
$
4

 
$
2,051

Net income
—

 
428

 
—

 
428

Dividends to ITC Investment Holdings
—

 
(250
)
 
—

 
(250
)
Other comprehensive income, net of tax (Note 15)
—

 
—

 
3

 
3

BALANCE, DECEMBER 31, 2019
$
892

 
$
1,333

 
$
7

 
$
2,232

See notes to consolidated financial statements.


47

ITC HOLDINGS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
Year Ended December 31,
(In millions)
2019
 
2018
 
2017
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
 
 
Net income
$
428

 
$
330

 
$
319

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
 
Depreciation and amortization expense
203

 
180

 
169

Recognition, refund and collection of revenue accruals and deferrals — including accrued interest
(55
)
 
17

 
34

Deferred income tax expense
135

 
107

 
195

Allowance for equity funds used during construction
(29
)
 
(33
)
 
(33
)
Share-based compensation
32

 
6

 
2

Other
10

 
4

 
9

Changes in assets and liabilities, exclusive of changes shown separately:
 
 
 
 
 
Accounts receivable
(10
)
 
17

 
(17
)
Income tax receivable
1

 
14

 
—

Accounts payable
(11
)
 
6

 
(3
)
Accrued interest
(2
)
 
(10
)
 
7

Accrued taxes
3

 
7

 
5

Net refund related to return on equity complaints
(82
)
 
6

 
(113
)
Other current and non-current assets and liabilities, net
6

 
2

 
33

Net cash provided by operating activities
629

 
653

 
607

CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
 
 
Expenditures for property, plant and equipment
(865
)
 
(769
)
 
(755
)
Contributions in aid of construction
10

 
21

 
21

Other
1

 
1

 
(10
)
Net cash used in investing activities
(854
)
 
(747
)
 
(744
)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
 
 
Issuance of long-term debt, net of discount
175

 
400

 
1,199

Borrowings under revolving credit agreements
1,090

 
832

 
1,065

Borrowings under term loan credit agreements
200

 
—

 
250

Net (repayment) issuance of commercial paper, net of discount
200

 
—

 
(148
)
Retirement of long-term debt — including extinguishment of debt costs
(203
)
 
(100
)
 
(477
)
Repayments of revolving credit agreements
(999
)
 
(844
)
 
(1,178
)
Repayments of term loan credit agreements
—

 
(50
)
 
(200
)
Dividends to ITC Investment Holdings
(250
)
 
(200
)
 
(300
)
Refundable deposits from generators for transmission network upgrades
19

 
6

 
16

Repayment of refundable deposits from generators for transmission network upgrades
(8
)
 
(3
)
 
(28
)
Other
(3
)
 
(5
)
 
(5
)
Net cash provided by financing activities
221

 
36

 
194

NET (DECREASE) INCREASE IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH
(4
)
 
(58
)
 
57

CASH, CASH EQUIVALENTS AND RESTRICTED CASH — Beginning of period
10

 
68

 
11

CASH, CASH EQUIVALENTS AND RESTRICTED CASH — End of period
$
6

 
$
10

 
$
68

See notes to consolidated financial statements.


48

ITC HOLDINGS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1.    GENERAL
ITC Holdings and its subsidiaries are engaged in the transmission of electricity in the United States. In 2016, ITC Holdings became a wholly-owned subsidiary of ITC Investment Holdings. Fortis owns a majority indirect equity interest in ITC Investment Holdings, with GIC holding an indirect equity interest of 19.9%. Through our Regulated Operating Subsidiaries, we own and operate high-voltage electric transmission systems in Michigan’s Lower Peninsula and portions of Iowa, Minnesota, Illinois, Missouri, Kansas, and Oklahoma that transmit electricity from generating stations to local distribution facilities connected to our transmission systems. Our business strategy is to own, operate, maintain and invest in transmission infrastructure in order to enhance system integrity and reliability, reduce transmission constraints and support new generating resources to interconnect to our transmission systems.
Our Regulated Operating Subsidiaries are independent electric transmission utilities, with rates regulated by the FERC and established on a cost-of-service model. ITCTransmission’s service area is located in southeastern Michigan, while METC’s service area covers approximately two-thirds of Michigan’s Lower Peninsula and is contiguous with ITCTransmission’s service area. ITC Midwest’s service area is located in portions of Iowa, Minnesota, Illinois and Missouri and ITC Great Plains currently owns assets located in Kansas and Oklahoma. MISO bills and collects revenues from the MISO Regulated Operating Subsidiaries’ customers. SPP bills and collects revenue from ITC Great Plains’ customers. ITC Interconnection currently owns assets in Michigan and earns revenues based on its facilities reimbursement agreement with a merchant generating company.
2.    RECENT ACCOUNTING PRONOUNCEMENTS
Recently Adopted Pronouncements
Accounting for Leases
Effective January 1, 2019, we adopted accounting guidance that requires lessees to recognize a right-of-use asset and lease liability for most leases, along with additional quantitative and qualitative disclosures. We elected to apply transition relief which permitted us to adopt the new guidance on a modified retrospective basis at the adoption date (i.e., January 1, 2019) as opposed to at the beginning of the earliest period presented in the financial statements (i.e., January 1, 2017). Therefore, while we began applying the new guidance as of January 1, 2019, prior period comparative financial statements and disclosures will continue to be presented under previous lease accounting guidance.
In connection with our adoption of the new guidance, we elected various practical expedients and made certain accounting policy elections, including:
•
a “package of three” practical expedients that must be taken together and allowed us to not reassess:
◦
whether any expired or existing contract is a lease or contains a lease,
◦
the lease classification of any expired or existing leases, and
◦
the initial direct costs for any existing leases;
•
a practical expedient that permits entities to not evaluate existing land easements at adoption that were not previously accounted for as leases; and
•
an accounting policy election to not apply the recognition requirements to short-term leases (i.e., leases with terms of 12 months or less).
Our leasing activities primarily relate to office facilities, but we also have limited leasing activity relating to equipment and storage facilities. As of January 1, 2019, adoption of the guidance resulted in recognition of right-of-use lease assets of $3 million, current lease liabilities of $1 million, and non-current lease liabilities of $2 million. The adoption of this guidance did not have any impact on retained earnings or net income. We also added disclosures as a result of our adoption of the guidance; refer to Note 10 for more information on our leasing activities.


49

Targeted Improvements to Accounting for Hedging Activities
In August 2017, the FASB issued authoritative guidance to make targeted improvements to hedge accounting to better align with an entity’s risk management objectives and to reduce the complexity of hedge accounting. Among other changes, the new guidance simplifies hedge accounting by (a) allowing more time for entities to complete initial quantitative hedge effectiveness assessments, (b) enabling entities to elect to perform subsequent effectiveness assessments qualitatively, (c) eliminating the concept of recognizing periodic hedge ineffectiveness for cash flow hedges, (d) requiring the change in fair value of a derivative to be recorded in the same consolidated statements of comprehensive income line item as the earnings effect of the hedged item, and (e) permitting additional hedge strategies to qualify for hedge accounting. In addition, the guidance modifies existing disclosure requirements and adds new disclosure requirements. We adopted the guidance as of January 1, 2019; however, adoption of the accounting standard did not have a material impact on our financial statements or disclosures.
Pension and Other Postretirement Plan Disclosures
In August 2018, the FASB issued authoritative guidance modifying the disclosure requirements for defined benefit pension and other postretirement plans. The new guidance requires disclosures including (a) the weighted average interest credit rates used for cash balance pension plans, (b) a narrative description of the reasons for significant gains and losses affecting the benefit obligation for the period, and (c) an explanation of other significant changes in the benefit obligation or plan assets. In addition, the guidance removes previously required disclosures including, among others, the requirement for public entities to disclose the effects of a one-percentage-point change on the assumed health care costs and the effect of the change in rates on service cost, interest cost, and the benefit obligation for postretirement health care benefits. The new guidance, which is effective for fiscal years ending after December 15, 2020 with early adoption permitted, is required to be adopted on a retrospective basis. We early adopted this guidance in the 2019 consolidated financial statements and adjusted our disclosures accordingly.
Recently Issued Pronouncements
We have considered all new accounting pronouncements issued by the FASB and concluded the following accounting guidance, which has not yet been adopted by us, may have a material impact on our consolidated financial statements.
Accounting for Cloud Computing Arrangements
In August 2018, the FASB issued authoritative guidance to address the accounting for implementation costs incurred in a cloud computing agreement that is a service contract. The new standard aligns the accounting for implementation costs incurred in a cloud computing arrangement as a service contract with existing guidance on capitalizing costs associated with developing or obtaining internal-use software. In addition, the new guidance requires entities to expense capitalized implementation costs of a cloud computing arrangement that is a service contract over the term of the agreement and to present the expense in the same income statement line item as the hosting fees. The guidance is effective for fiscal years beginning after December 15, 2019 with early adoption permitted; however, we have elected not to early adopt. Prospective or retrospective adoption is permitted; we plan to adopt prospectively. We do not expect adoption of this standard to have a material impact on our annual consolidated financial statements.
3.    SIGNIFICANT ACCOUNTING POLICIES
A summary of the major accounting policies followed in the preparation of the accompanying consolidated financial statements, which conform to GAAP, is presented below:
Principles of Consolidation — ITC Holdings consolidates its majority owned subsidiaries. We eliminate all intercompany balances and transactions.
Use of Estimates — The preparation of the consolidated financial statements requires us to use estimates and assumptions that impact the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. Actual results may differ from our estimates.
Regulation — Our Regulated Operating Subsidiaries are subject to the regulatory jurisdiction of the FERC, which issues orders pertaining to rates, recovery of certain costs, including the costs of transmission assets and regulatory assets, conditions of service, accounting, financing authorization and operating-related


50

matters. The utility operations of our Regulated Operating Subsidiaries meet the accounting standards set forth by the FASB for the accounting effects of certain types of regulation. These accounting standards recognize the cost based rate setting process, which results in differences in the application of GAAP between regulated and non-regulated businesses. These standards require the recording of regulatory assets and liabilities for certain transactions that would have been recorded as revenue and expense in non-regulated businesses. Regulatory assets represent costs that will be included as a component of future tariff rates and regulatory liabilities represent amounts provided in the current tariff rates that are intended to recover costs expected to be incurred in the future or amounts to be refunded to customers.
Cash and Cash Equivalents — We consider all unrestricted highly-liquid temporary investments with an original maturity of three months or less at the date of purchase to be cash equivalents.
Restricted Cash and Restricted Cash Equivalents — Restricted cash and restricted cash equivalents include cash and cash equivalents that are legally or contractually restricted for use or withdrawal or are formally set aside for a specific purpose.
Accounts Receivable — We recognize losses for uncollectible accounts based on specific identification of any such items. As of December 31, 2019, 2018 and 2017 we did not have an accounts receivable reserve.
Inventories — Materials and supplies inventories are valued at average cost. Additionally, the costs of warehousing activities are recorded here and included in the cost of materials when requisitioned.
Property, Plant and Equipment — Depreciation and amortization expense on property, plant and equipment was $194 million, $170 million and $160 million for 2019, 2018 and 2017, respectively.
Property, plant and equipment in service at our Regulated Operating Subsidiaries is stated at its original cost when first devoted to utility service. The gross book value of assets retired less salvage proceeds is charged to accumulated depreciation. The provision for depreciation of transmission assets is a significant component of our Regulated Operating Subsidiaries’ cost of service under FERC-approved rates. Depreciation is computed over the estimated useful lives of the assets using the straight-line method for financial reporting purposes and accelerated methods for income tax reporting purposes. The composite depreciation rate for our Regulated Operating Subsidiaries included in our consolidated statements of comprehensive income was 2.0% for 2019, 2018 and 2017. The composite depreciation rates include depreciation primarily on transmission station equipment, towers, poles and overhead and underground lines that have a useful life ranging from 45 to 60 years. The portion of depreciation expense related to asset removal costs is added to regulatory liabilities or deducted from regulatory assets and removal costs incurred are deducted from regulatory liabilities or added to regulatory assets. Certain of our Regulated Operating Subsidiaries capitalize to property, plant and equipment AFUDC in accordance with the FERC regulations. AFUDC represents the composite cost incurred to fund the construction of assets, including interest expense and a return on equity capital devoted to construction of assets. The interest component of AFUDC was a reduction to interest expense of $8 million for 2019 and $9 million for 2018 and 2017.
For acquisitions of property, plant and equipment greater than the net book value (other than asset acquisitions accounted for under the purchase method of accounting that result in goodwill), the acquisition premium is recorded to property, plant and equipment and amortized over the estimated remaining useful lives of the assets using the straight-line method for financial reporting purposes and accelerated methods for income tax reporting purposes.
Property, plant and equipment includes capital equipment inventory stated at original cost consisting of items that are expected to be used exclusively for capital projects.
Property, plant and equipment at ITC Holdings and non-regulated subsidiaries is stated at its acquired cost. Proceeds from salvage less the net book value of the disposed assets is recognized as a gain or loss on disposal. Depreciation is computed based on the acquired cost less expected residual value and is recognized over the estimated useful lives of the assets on a straight-line method for financial reporting purposes and accelerated methods for income tax reporting purposes.
Generator Interconnection Projects and Contributions in Aid of Construction — Certain capital investment at our Regulated Operating Subsidiaries relates to investments made under generator interconnection agreements. The generator interconnection agreements typically consist of both transmission network upgrades, which are a category of upgrades deemed by the FERC to benefit the transmission system as a


51

whole, as well as direct connection facilities, which are necessary to interconnect the generating facility to the transmission system and primarily benefit the generating facility. As a result, generator interconnection agreements typically require the generator to make a contribution in aid of construction to our Regulated Operating Subsidiaries to cover the cost of certain investments made by us as part of the agreement.
Our investments in transmission facilities are recorded to property, plant and equipment, and are recorded net of any contribution in aid of construction. We also receive refundable deposits from the generator for certain investment in network upgrade facilities in advance of construction, which are recorded to current or non-current liabilities depending on the expected refund date.
Fair Value Through Net Income — We have certain investments in mutual funds, including fixed income securities and equity securities that are classified as fair value through net income. The fixed income security investments primarily fund our two supplemental nonqualified, noncontributory, retirement benefit plans for selected management employees as described in Note 13. Beginning on January 1, 2018, all gains and losses associated with our mutual funds as described in Note 14 are recorded in earnings. Previously, unrealized gains and losses on certain available-for-sale investments were recorded in AOCI.
Impairment of Long-Lived Assets — Other than goodwill, our long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate the carrying amount of an asset may not be recoverable. If the carrying amount of the asset exceeds the expected undiscounted future cash flows generated by the asset, the asset is written down to its estimated fair value and an impairment loss is recognized in our consolidated statements of comprehensive income.
Goodwill and Other Intangible Assets — Goodwill is not subject to amortization; however, goodwill is required to be assessed for impairment, and a resulting write-down, if any, is to be reflected in operating expense. We have goodwill recorded relating to our acquisitions of ITCTransmission and METC and ITC Midwest’s acquisition of the IP&L transmission assets. Goodwill is reviewed at the reporting unit level at least annually for impairment and whenever facts or circumstances indicate that the value of goodwill may be impaired. Our reporting units are ITCTransmission, METC and ITC Midwest as each entity represents an individual operating segment to which goodwill has been assigned.
In order to perform an impairment analysis, we have the option of performing a qualitative assessment to determine whether the existence of events or circumstances leads to a determination that it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, in which case no further testing is required. If an entity bypasses the qualitative assessment or performs a qualitative assessment but determines that it is more likely than not that a reporting unit’s fair value is less than its carrying amount, a quantitative, fair value-based test is performed to assess and measure goodwill impairment, if any. If a quantitative assessment is performed, we determine the fair value of our reporting units using valuation techniques based on discounted future cash flows under various scenarios and consider estimates of market-based valuation multiples for companies within the peer group of our reporting units.
We completed our annual goodwill impairment test for our reporting units as of October 1, 2019 and determined that no impairment exists. There were no events subsequent to October 1, 2019 that indicated impairment of our goodwill. Our intangible assets other than goodwill have finite lives and are amortized over their useful lives. Refer to Note 9 for additional discussion on our goodwill and intangible assets.
Deferred Financing Fees and Discount or Premium on Debt — Costs related to the issuance of long-term debt are generally recorded as a direct deduction from the carrying amount of the related debt and amortized over the life of the debt issue. Debt issuance costs incurred prior to the associated debt funding are presented as an asset. Unamortized debt issuance costs associated with the revolving credit agreements, commercial paper and other similar arrangements are presented as an asset (regardless of whether there are any amounts outstanding under those credit facilities) and amortized over the life of the particular arrangement. The debt discount or premium related to the issuance of long-term debt is recorded to long-term debt and amortized over the life of the debt issue. We recorded $5 million during the years ended December 31, 2019 and 2018 and $4 million during the year ended December 31, 2017 to interest expense for the amortization of deferred financing fees and debt discounts.
Asset Retirement Obligations — A conditional asset retirement obligation is a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within our control. We have identified conditional asset retirement obligations primarily


52

associated with the removal of equipment containing PCBs and asbestos. We record a liability at fair value for a legal asset retirement obligation in the period in which it is incurred. When a new legal obligation is recorded, we capitalize the costs of the liability by increasing the carrying amount of the related long-lived asset. We accrete the liability to its present value each period and depreciate the capitalized cost over the useful life of the related asset. At the end of the asset’s useful life, we settle the obligation for its recorded amount. We recognize regulatory assets for the timing differences between the incurred costs to settle our legal asset retirement obligations and the recognition of such obligations as applicable for our Regulated Operating Subsidiaries. There were no significant changes to our asset retirement obligations in 2019. Our asset retirement obligations as of December 31, 2019 and 2018 of $6 million and $5 million, respectively, are included in other liabilities.
Derivatives and Hedging — We may use derivative financial instruments, including interest rate swap contracts, to manage our exposure to fluctuations in interest rates. For derivative instruments that have been designated and qualify as cash flow hedges of the exposure to variability in expected future cash flows, the unrealized gain or loss on the derivative is initially reported, net of tax, as a component of other comprehensive income (loss) and reclassified to the consolidated statements of comprehensive income when the underlying hedged transaction affects net income. Refer to Note 11 for additional discussion regarding derivative instruments. Cash flows related to derivative instruments that are designated in hedging relationships are generally classified on the consolidated statements of cash flows in the same category as the cash flows from the associated hedged item. The fair values of derivatives are recognized as current or long-term assets and liabilities depending on the timing of settlements and resulting cash flows.
Contingent Obligations — We are subject to a number of federal and state laws and regulations, as well as other factors and conditions that potentially subject us to environmental, litigation and other risks. We periodically evaluate our exposure to such risks and record liabilities for those matters when a loss is considered probable and reasonably estimable. We reverse the liabilities recorded for those matters when a loss is no longer considered probable. Our liabilities exclude any estimates for legal costs not yet incurred associated with handling these matters. The adequacy of liabilities can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect our consolidated financial statements.
Leases — We enter into operating leases where we are the lessee, primarily for office facilities, equipment, and storage facilities. When a contract contains a lease such that it conveys the right to control the use of an identified asset for a period of time in exchange for consideration, we record and measure right-of-use assets and lease liabilities at the present value of future lease payments. We calculate the present value using our incremental borrowing rate, which is a secured interest rate based on the remaining lease term. Our lease payments are substantially all fixed and, in some cases, escalate according to a schedule. We account for office facility leases, which may have lease components and non-lease components, as a single lease component. Short-term leases with an initial term of twelve months or less are not recorded on the consolidated statements of financial position. We recognize expenses related to our operating lease obligations on a straight-line basis over the term of the lease.
Revenues — Substantially all of our revenue from contracts with customers is generated from providing transmission services to customers based on tariff rates, as approved by the FERC. Revenues from the transmission of electricity are recognized as services are provided based on our FERC-approved cost-based Formula Rates. We record a reserve for revenue subject to refund when such refund is probable and can be reasonably estimated. This reserve is recorded as a reduction to operating revenues.
The cost-based Formula Rates at our Regulated Operating Subsidiaries include a true-up mechanism that compares the actual revenue requirements of our Regulated Operating Subsidiaries to their billed revenues for each year to determine any over- or under-collection of revenue requirements and we record a revenue accrual or deferral for the difference. The true-up mechanisms under our Formula Rates are considered alternative revenue programs of rate-regulated utilities. Operating revenues arising from these alternative revenue programs are presented on our consolidated statements of comprehensive income in the line “Formula Rate true-up”, which is separate from the reporting of our tariff revenues, which are presented in the line “Transmission and other services”. Only the initial origination of our alternative revenue program revenue is reported in the Formula Rate true-up line on our consolidated statements of comprehensive income. When those amounts are subsequently included in the price of utility service and billed or refunded


53

to customers, we account for that event as the recovery or settlement of the associated regulatory asset or regulatory liability, respectively. Refer to Note 6 under “Cost-Based Formula Rates with True-Up Mechanism” and Note 4 under “Formula Rate True-Up” for a discussion of our revenue accounting under our cost-based Formula Rates.
Share-Based Payment and Employee Share Purchase Plan — Under the terms of the 2017 Omnibus Plan, we may grant long term incentive awards of PBUs and SBUs. The awards are classified as liability awards based on the cash settlement feature. The award units earn dividend equivalents which are also settled in cash at the end of the vesting period. Compensation cost is recognized over the expected vesting period and remeasured each reporting period based on Fortis’ stock price. The PBUs are also remeasured each reporting period based on the applicable market and performance conditions in the awards. Compensation cost is adjusted for forfeitures in the period in which they occur and the final measure of compensation cost for the awards is based on the cash settlement amount.
We also have an Employee Share Purchase Plan which enables ITC employees to purchase shares of Fortis common stock. Our cost of the plan is based on the value of our contribution, as additional compensation to a participating employee, equal to 10% of an employee’s contribution up to a maximum annual contribution of 1% of an employee’s base pay and an amount equal to 10% of all dividends payable by Fortis on the Fortis shares allocated to an employee’s ESPP account.
Refer to Note 16 for additional discussion of the plans.
Comprehensive Income (Loss) — Comprehensive income (loss) is the change in common stockholder’s equity during a period arising from transactions and events from non-owner sources, including net income and any gain or loss arising from our interest rate swaps.
Income Taxes — Deferred income taxes are recognized for the expected future tax consequences of events that have been recognized in the consolidated financial statements or tax returns. Deferred income tax assets and liabilities are determined based on the differences between the financial statements and the tax bases of various assets and liabilities, using the tax rates expected to be in effect for the year in which the differences are expected to reverse, and classified as non-current in our consolidated statements of financial position.
The accounting standards for uncertainty in income taxes prescribe a recognition threshold and a measurement attribute for tax positions taken, or expected to be taken, in a tax return that may not be sustainable. As of December 31, 2019, we have not recognized any uncertain income tax positions.
We file our federal income tax returns as part of the FortisUS consolidated federal tax return starting with the year ended December 31, 2016 and we are a party to an intercompany tax sharing agreement that establishes the method for determining tax liabilities that are due and allocating tax attributes that are utilized on the consolidated income tax return. We have historically filed federal income tax returns with the IRS and continue to file with various state and city jurisdictions. Our prior consolidated federal tax returns are no longer subject to U.S. federal tax examinations for tax years 2016 and earlier. State and city jurisdictions that remain subject to examination range from tax years 2015 to 2018. In the event we are assessed interest or penalties by any income tax jurisdictions, interest and penalties would be recorded as interest expense and other expense, respectively, in our consolidated statements of comprehensive income.
Refer to Notes 7 and 12 for additional discussion on income taxes and tax reform.
4.    REVENUE
Our total revenues are comprised of revenues which arise from three classifications including transmission services, other services, and Formula Rate true-up. As other services revenue is immaterial, it is presented in combination with transmission services on the consolidated statements of comprehensive income.
Transmission Services
Through our Regulated Operating Subsidiaries, we generate nearly all our revenue from providing electric transmission services over our transmission systems. As independent transmission companies, our transmission services are provided and revenues are received based on our tariffs, as approved by the FERC. The transmission revenue requirements at our Regulated Operating Subsidiaries are set annually using Formula Rates and remain in effect for a one-year period. By updating the inputs to the formula and resulting rates on an annual basis, the


54

revenues at our Regulated Operating Subsidiaries reflect changing operating data and financial performance, including the amount of network load on their transmission systems (for our MISO Regulated Operating Subsidiaries), operating expenses and additions to property, plant and equipment when placed in service, among other items.
We recognize revenue for transmission services over time as transmission services are provided to customers (generally using an output measure of progress based on transmission load delivered). Customers simultaneously receive and consume the benefits provided by the Regulated Operating Subsidiaries’ services. We recognize revenue in the amount to which we have the right to invoice because we have a right to consideration in an amount that corresponds directly with the value to the customer of performance completed to date. As billing agents, MISO and SPP independently bill our customers on a monthly basis and collect fees for the use of our transmission systems. No component of the transaction price is allocated to unsatisfied performance obligations.
Transmission service revenue includes an estimate for unbilled revenues from service that has been provided but not billed by the end of an accounting period. Unbilled revenues are dependent upon a number of factors that require management’s judgment including estimates of transmission network load (for the MISO Regulated Operating Subsidiaries) and preliminary information provided by billing agents. Due to the seasonal fluctuations of actual load, the unbilled revenue amount generally increases during the spring and summer and decreases during the fall and winter. See Note 5 for information on changes in unbilled accounts receivable.
Other Services
Other services revenue consists of rental revenues, easement revenues, and amounts from providing ancillary services. A portion of other services revenue is treated as a revenue credit and reduces gross revenue requirement when calculating net revenue requirement under our Formula Rates. Total other services revenue was $7 million, $5 million and $6 million for the years ended December 31, 2019, 2018 and 2017, respectively.
Formula Rate True-Up
The true-up mechanism under our Formula Rates is considered an alternative revenue program of a rate-regulated utility given it permits our Regulated Operating Subsidiaries to adjust future rates in response to past activities or completed events in order to collect our actual revenue requirements under our Formula Rates. In accordance with our accounting policy, only the current year origination of the true-up is reported as a Formula Rate true-up. See “Cost-Based Formula Rates with True-Up Mechanism” in Note 6 for more information on our Formula Rates.
5.    ACCOUNTS RECEIVABLE
The following table presents the components of accounts receivable on the consolidated statements of financial position:
 
December 31,
(In millions)
2019
 
2018
 
2017
 
2016
Trade accounts receivable
$
2

 
$
2

 
$
2

 
$
2

Unbilled accounts receivable
102

 
92

 
108

 
92

Due from affiliates
1

 
1

 
—

 
1

Other
12

 
7

 
9

 
13

Total accounts receivable
$
117

 
$
102

 
$
119

 
$
108


6.    REGULATORY MATTERS
Cost-Based Formula Rates with True-Up Mechanism
The transmission revenue requirements at our Regulated Operating Subsidiaries are set annually using Formula Rates and remain in effect for a 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


55

will continue to use the formula to calculate their respective annual revenue requirements unless the FERC determines the resulting rates to be unjust and unreasonable and another mechanism is determined by the FERC to be just and reasonable. See “Rate of Return on Equity Complaints” in Note 19 for detail on ROE matters for our MISO Regulated Operating Subsidiaries and "Incentive Adders for Transmission Rates" discussed in Note 6 herein.
The cost-based Formula Rates at our Regulated Operating Subsidiaries include a true-up mechanism that compares the actual revenue requirements of our Regulated Operating Subsidiaries to their billed revenues for each year to determine any over- or under-collection of revenue requirements. Revenue is recognized for services provided during each reporting period based on actual revenue requirements calculated using the formula. Our Regulated Operating Subsidiaries accrue or defer revenues to the extent that the actual revenue requirement for the reporting period is higher or lower, respectively, than the amounts billed relating to that reporting period. The amount of accrued or deferred revenues is reflected in future revenue requirements and thus flows through to customer bills within two years under the provisions of our Formula Rates.
The net changes in regulatory assets and liabilities associated with our Regulated Operating Subsidiaries’ Formula Rate revenue accruals and deferrals, including accrued interest, were as follows during the year ended December 31, 2019:
(In millions)
Total
Net regulatory liabilities as of December 31, 2018
$
(52
)
Net refund of 2017 revenue deferrals and accruals, including accrued interest
16

Net revenue accrual for the year ended December 31, 2019
41

Net accrued interest payable for the year ended December 31, 2019
(2
)
Net regulatory assets as of December 31, 2019
$
3


Regulatory assets and liabilities associated with our Regulated Operating Subsidiaries’ Formula Rate revenue accruals and deferrals, including accrued interest, are recorded in the consolidated statements of financial position as follows:
 
December 31,
(In millions)
2019
 
2018
Current regulatory assets
$
12

 
$
12

Non-current regulatory assets
43

 
12

Current regulatory liabilities
(51
)
 
(27
)
Non-current regulatory liabilities
(1
)
 
(49
)
Net regulatory assets (liabilities)
$
3

 
$
(52
)

Incentive Adders for Transmission Rates
The FERC has authorized the use of ROE incentives, or adders, that can be applied to the rates of TOs when certain conditions are met. Our MISO Regulated Operating Subsidiaries and ITC Great Plains utilize ROE adders related to independent transmission ownership and RTO participation.
MISO Regulated Operating Subsidiaries
On April 20, 2018, Consumers Energy, IP&L, Midwest Municipal Transmission Group, Missouri River Energy Services, Southern Minnesota Municipal Power Agency and WPPI Energy filed a complaint with the FERC under section 206 of the FPA, challenging the adders for independent transmission ownership that are included in transmission rates charged by the MISO Regulated Operating Subsidiaries. The adders for independent transmission ownership allowed up to 50 basis points or 100 basis points to be added to the MISO Regulated Operating Subsidiaries’ authorized ROE, subject to any ROE cap established by the FERC. On October 18, 2018, the FERC issued an order granting the complaint in part, setting revised adders for independent transmission ownership for each of the MISO Regulated Operating Subsidiaries to 25 basis points, and requiring the MISO Regulated Operating Subsidiaries to include the revised adders, effective April 20, 2018, in their Formula Rates. In addition, the order directed the MISO Regulated Operating Subsidiaries to provide refunds, with interest, for the period from April 20, 2018 through October 18, 2018. The MISO Regulated Operating Subsidiaries began


56

reflecting the 25 basis point adder for independent transmission ownership in transmission rates in November 2018. Refunds of $7 million were primarily made in the fourth quarter of 2018 and were completed in the first quarter of 2019. The MISO Regulated Operating Subsidiaries sought rehearing of the FERC’s October 18, 2018 order, and on July 18, 2019, the FERC denied the rehearing request. On September 11, 2019, the MISO Regulated Operating Subsidiaries filed an appeal of the FERC’s order in the D.C. Circuit Court. On December 16, 2019, the D.C. Circuit Court established a briefing schedule for the appeal. Initial briefs were filed on January 27, 2020 and reply briefs are due to be filed in the second quarter of 2020. We do not expect the final resolution of this proceeding to have a material adverse impact on our consolidated results of operations, cash flows or financial condition.
Based on the October 18, 2018 FERC order, the authorized incentive adders for the MISO Regulated Operating Subsidiaries have been revised to include a 25 basis point adder for independent transmission ownership. Prior to the October 18, 2018 FERC order, the adders for independent transmission ownership were 100 basis points at each of ITCTransmission and METC and 50 basis points at ITC Midwest. For each of the years ended December 31, 2019, 2018 and 2017, the authorized incentive adders for the MISO Regulated Operating Subsidiaries included a 50 basis point adder for RTO participation. See Note 19 for information regarding the MISO ROE Complaints and the associated impact to the base ROE of our MISO Regulated Operating Subsidiaries.
ITC Great Plains
On June 11, 2019, KCC filed a complaint with the FERC under section 206 of the FPA, challenging the ROE adder for independent transmission ownership that is included in the transmission rate charged by ITC Great Plains. The complaint argues that because ITC Great Plains is similarly situated to our MISO Regulated Operating Subsidiaries with respect to ownership by Fortis and GIC, the same rationale by which the FERC lowered the MISO Regulated Operating Subsidiaries adders for independent transmission ownership, as discussed above, also applies to ITC Great Plains. The adder for independent transmission ownership allows up to 100 basis points to be added to the ITC Great Plains authorized ROE, subject to any ROE cap established by the FERC. ITC Great Plains filed an answer to the complaint on July 1, 2019 asking the FERC to deny the complaint since KCC showed no evidence that ITC Great Plains’ independence or the benefits it provides as an independent TO has been compromised or reduced as a result of the Fortis and GIC acquisition. As of December 31, 2019, we had recorded an estimated current regulatory liability of $2 million related to this complaint. We do not expect the resolution of this proceeding to have a material adverse impact on our consolidated results of operations, cash flows or financial condition.
As of December 31, 2019, the authorized ROE used by ITC Great Plains is 12.16% and is composed of a base ROE of 10.66% with a 100 basis point adder for independent transmission ownership and a 50 basis point adder for RTO participation.
Calculation of Accumulated Deferred Income Tax Balances in Projected Formula Rates
On June 21, 2018, the FERC issued an order initiating a proceeding and paper hearings, pursuant to Section 206 of the FPA, to examine the methodology used by a group of TOs, including ITCTransmission and ITC Midwest, for calculating balances of ADIT in forward-looking Formula Rates. The FERC previously concluded that the two-step averaging methodology for ADIT is no longer necessary to comply with IRS normalization rules in light of IRS guidance issued in 2017. On August 27, 2018, our MISO Regulated Operating Subsidiaries submitted a filing with the FERC under Section 205 of the FPA to eliminate the use of the two-step averaging methodology in the calculation of ADIT balances for the projected test year and modify the manner by which they calculate average ADIT balances in their annual transmission Formula Rate true-up calculation, subject to receiving guidance from the IRS to respond to the FERC order. On April 10, 2019, our MISO Regulated Operating Subsidiaries received formal guidance from the IRS, which we believe is consistent with the filings that have been made to date in these proceedings.
On December 20, 2018, the FERC issued an order that ITCTransmission and ITC Midwest make a compliance filing to implement the changes to their Formula Rate templates and formally instituted a proceeding against METC pursuant to Section 206 of the FPA to implement the changes. On May 16, 2019, the FERC issued an order accepting in part and rejecting in part ITCTransmission’s and ITC Midwest’s January 22, 2019 compliance filing and ordered them to make another compliance filing within 30 days of the date of the order. Specifically, the FERC accepted the portion of the compliance filing that removed the two-step averaging methodology, but rejected the compliance filing insofar as it carried proration to the Formula Rate true-up calculation because the FERC found that was beyond the scope of its previous orders in the docket. Additionally, on May 16, 2019, the FERC issued


57

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


58

7.    REGULATORY ASSETS AND LIABILITIES
Regulatory Assets
The following table summarizes the regulatory asset balances:
 
December 31,
(In millions)
2019
 
2018
Regulatory Assets:
 
 
 
Current:
 
 
 
Revenue accruals (including accrued interest of $1 and less than $1 as of December 31, 2019 and 2018, respectively) (a)
$
12

 
$
12

Total current
12

 
12

Non-current:
 
 
 
Revenue accruals (including accrued interest of $1 and less than $1 as of December 31, 2019 and 2018, respectively) (a)
43

 
12

ITCTransmission ADIT deferral (net of accumulated amortization of $51 and $48 as of December 31, 2019 and 2018, respectively)
10

 
13

METC ADIT deferral (net of accumulated amortization of $31 and $29 as of December 31, 2019 and 2018, respectively)
12

 
14

METC regulatory deferrals (net of accumulated amortization of $10 and $9 as of December 31, 2019 and 2018, respectively)
5

 
6

Income taxes recoverable related to AFUDC equity
99

 
91

ITC Great Plains start-up, development and pre-construction (net of accumulated amortization of $6 and $5 as of December 31, 2019 and 2018, respectively)
7

 
8

Pensions and postretirement
25

 
25

Income taxes recoverable related to implementation of the Michigan Corporate Income Tax and other state excess deficient taxes
7

 
7

Accrued asset removal costs
21

 
24

Total non-current
229

 
200

 
 
 
 
Total
$
241

 
$
212


____________________________
(a)
Refer to discussion of revenue accruals in Note 6 under “Cost-Based Formula Rates with True-Up Mechanism.” Our Regulated Operating Subsidiaries do not earn a return on the balance of these regulatory assets, but do accrue interest carrying costs, which are subject to rate recovery along with the principal amount of the revenue accrual.
ITCTransmission ADIT Deferral
The carrying amount of the ITCTransmission ADIT Deferral is the remaining unamortized balance of the portion of ITCTransmission’s purchase price in excess of fair value of net assets acquired from DTE Energy approved for inclusion in future rates by the FERC. The original amount recorded for this regulatory asset of $61 million is recognized in rates and amortized on a straight-line basis over 20 years beginning March 1, 2003. ITCTransmission includes the remaining unamortized balance of this regulatory asset in rate base. ITCTransmission recorded amortization expense of $3 million annually during 2019, 2018 and 2017, which is included in depreciation and amortization in our consolidated statements of comprehensive income and recovered through ITCTransmission’s cost-based Formula Rate template.
METC ADIT Deferral
The carrying amount of the METC ADIT Deferral is the remaining unamortized balance of the portion of METC’s purchase price in excess of the fair value of net assets acquired at the time MTH acquired METC from Consumers Energy approved for inclusion in future rates by the FERC. The original amount approved for recovery recorded for this regulatory asset of $43 million is recognized in rates and amortized on a straight-line basis over 18 years beginning January 1, 2007. METC includes the remaining unamortized balance of this regulatory asset in rate


59

base. METC recorded amortization expense of $2 million annually during 2019, 2018 and 2017, which is included in depreciation and amortization in our consolidated statements of comprehensive income and recovered through METC’s cost-based Formula Rate template.
METC Regulatory Deferrals
The carrying amount of the METC Regulatory Deferrals is the amount METC has deferred, as a regulatory asset, of depreciation and related interest expense associated with new transmission assets placed in service from January 1, 2001 through December 31, 2005 that were included on METC’s balance sheet at the time MTH acquired METC from Consumers Energy. The original amount recorded for this regulatory asset of $15 million, and approved for inclusion in future rates by the FERC, is recognized in rates and amortized over 20 years beginning January 1, 2007. METC includes the remaining unamortized balance of this regulatory asset in rate base. METC recorded amortization expense of $1 million annually during 2019, 2018 and 2017, which is included in depreciation and amortization in our consolidated statements of comprehensive income and recovered through METC’s cost-based Formula Rate template.
Income Taxes Recoverable Related to AFUDC Equity
Accounting standards for income taxes provide that a regulatory asset be recorded if it is probable that a future increase in taxes payable, relating to the book depreciation of AFUDC equity that has been capitalized to property, plant and equipment, will be recovered from customers through future rates. The regulatory asset for the tax effects of AFUDC equity is recovered over the life of the underlying book asset in a manner that is consistent with the depreciation of the AFUDC equity that has been capitalized to property, plant and equipment. This regulatory asset and the related offsetting deferred income tax liabilities do not affect rate base.
ITC Great Plains Start-Up, Development and Pre-Construction
In 2013, ITC Great Plains made a filing with the FERC, under Section 205 of the FPA, to recover start-up, development and pre-construction expenses in future rates. These expenses included certain costs incurred by ITC Great Plains for two regional cost sharing projects in Kansas prior to construction. In March 2015, FERC accepted ITC Great Plains’ request to commence amortization of the authorized regulatory assets, subject to refund, and set the matter for hearing and settlement judge procedures. In December 2015, the FERC issued an order accepting an uncontested settlement agreement establishing the amounts of the regulatory assets and associated carrying charges to be recovered. ITC Great Plains includes the unamortized balance of these regulatory assets in rate base and will amortize them over a 10-year period, beginning in the second quarter of 2015. The amortization expense is recorded to general and administrative expenses in our consolidated statements of comprehensive income and recovered through ITC Great Plains’ cost-based Formula Rate.
Pensions and Postretirement
Accounting standards for defined benefit pension and other postretirement plans for rate-regulated entities allow for amounts that otherwise would have been charged and/or credited to AOCI to be recorded as a regulatory asset or liability. As the unrecognized amounts recorded to this regulatory asset are recognized, expenses will be recovered from customers in future rates under our cost based Formula Rates. This regulatory asset is not included when determining rate base.
Income Taxes Recoverable Related to Implementation of the Michigan Corporate Income Tax
Under the Michigan Corporate Income Tax, we are taxed at a rate of 6.0% on federal taxable income attributable to our operations in the state of Michigan, subject to certain adjustments. In 2011, due to certain Michigan tax law changes we were required to establish new deferred income tax balances under the Michigan Corporate Income Tax, and the net result was incremental deferred state income tax liabilities at both ITCTransmission and METC. Under our cost-based Formula Rate, the future tax receivable as a result of the tax law change has resulted in the recognition of a regulatory asset, which will be collected from customers for the 23-year period and the 32-year period for ITCTransmission and METC, respectively, beginning in 2016. ITCTransmission and METC include this regulatory asset within deferred taxes for rate-making purposes when determining rate base.
Accrued Asset Removal Costs
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


60

asset and removal costs incurred are added to this regulatory asset. In addition, this regulatory asset has also been adjusted for timing differences between incurred costs to settle legal asset retirement obligations and the recognition of such obligations under the standards set forth by the FASB. Our Regulated Operating Subsidiaries include this item, excluding the cost component related to the recognition of our legal asset retirement obligations under the standards set forth by the FASB, as a reduction to accumulated depreciation for rate-making purposes, when determining rate base.
Regulatory Liabilities
The following table summarizes the regulatory liability balances:
 
December 31,
(In millions)
2019
 
2018
Regulatory Liabilities:
 
 
 
Current:
 
 
 
Revenue deferrals (including accrued interest of $4 and $2 as of December 31, 2019 and 2018, respectively) (a)
$
51

 
$
27

Refund liability related to return on equity complaints (including accrued interest of $6 and $18 as of December 31, 2019 and 2018, respectively) (b)
70

 
151

Estimated refund related to ITC Great Plains incentive adder complaint (c)
2

 
—

Total current
123

 
178

Non-current:
 
 
 
Revenue deferrals (including accrued interest of less than $1 and $1 as of December 31, 2019 and 2018, respectively) (a)
1

 
49

Accrued asset removal costs
72

 
71

Excess state income tax deductions
2

 
9

Income taxes refundable related to implementation of the TCJA
509

 
511

Total non-current
584

 
640

 
 
 
 
Total
$
707

 
$
818

____________________________
(a)
Refer to discussion of revenue deferrals in Note 6 under “Cost-Based Formula Rates with True-Up Mechanism.” Our Regulated Operating Subsidiaries accrue interest on the true-up amounts which will be refunded through rates along with the principal amount of revenue deferrals in future periods.
(b)
Refer to discussion of the refund liability in Note 19 under “Rate of Return on Equity Complaints.”
(c)
Refer to discussion of the ITC Great Plains incentive adder in Note 6 under “Incentive Adders for Transmission Rates.”
Accrued Asset Removal Costs
The carrying amount of the accrued asset removal costs represents the difference between incurred costs to remove property, plant and equipment and the estimated removal costs included and collected in rates. The portion of depreciation expense included in our depreciation rates related to asset removal costs is added to this regulatory liability and removal expenditures incurred are charged to this regulatory liability. Our Regulated Operating Subsidiaries include this item within accumulated depreciation for rate-making purposes and determining rate base.
Excess State Income Tax Deductions
We have taken state income tax deductions associated with property additions that exceed the tax basis of property, and the unrealized income tax benefits resulting from these deductions are expected to be refunded to customers through future rates when the income tax benefits are realized. This regulatory liability is included within deferred taxes for rate-making purposes when determining rate base.


61

Income Taxes Refundable Related to Implementation of the TCJA
In December 2017, the President of the United States signed into law the TCJA, which enacted significant changes to the Internal Revenue Code including a reduction in the U.S. federal corporate income tax rate from 35% to 21% effective for tax years beginning after 2017. The Company was required to revalue its deferred tax assets and liabilities at the new federal corporate income tax rate as of the date of the enactment of the TCJA, which resulted in lower net deferred tax liabilities and the establishment of a regulatory liability for excess deferred taxes at our Regulated Operating Subsidiaries. The excess deferred taxes are generally the result of accelerated federal tax deductions realized by our Regulated Operating Subsidiaries in periods when the U.S. federal corporate income tax rate was 35% and now would be returned to customers in a period where the U.S. federal corporate income tax rate is 21%. As the excess deferred taxes must be returned to customers this regulatory liability is recognized. For our Regulated Operating Subsidiaries, our deferred taxes are subject to a normalization method of accounting for the excess tax reserves resulting from the change in the federal statutory tax rate which involves the use of ARAM for the determination of the timing of the return of the excess deferred taxes to customers associated with public utility property. In addition, a portion of our excess deferred taxes at our Regulated Operating Subsidiaries are associated with other types of deferred taxes that are not related to public utility property and are subject to amortization. We have elected to amortize these excess deferred taxes using RSGM and have determined that it is a reasonable method of amortization. During the years ended December 31, 2019 and 2018, we recorded $1 million and less than $1 million, respectively, of amortization related to the excess deferred taxes under ARAM and RSGM. The net regulatory liability is included within deferred taxes for rate-making purposes when determining rate base.
8.    PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment — net consisted of the following:
 
December 31,
(In millions)
2019
 
2018
Property, plant and equipment
 
 
 
Regulated Operating Subsidiaries:
 
 
 
Property, plant and equipment in service
$
9,973

 
$
9,113

Construction work in progress
375

 
465

Capital equipment inventory
99

 
79

Other
51

 
18

ITC Holdings and other
14

 
14

Total
10,512

 
9,689

Less: Accumulated depreciation and amortization
(1,930
)
 
(1,779
)
Property, plant and equipment, net
$
8,582

 
$
7,910


Additions to property, plant and equipment in service and construction work in progress during 2019 and 2018 were due primarily to asset acquisitions and projects to upgrade or replace existing transmission plant to improve the reliability of our transmission systems as well as transmission infrastructure to support generator interconnections and investments that provide regional benefits such as our MVPs.
9.    GOODWILL AND INTANGIBLE ASSETS
Goodwill
At December 31, 2019 and 2018, we had goodwill balances recorded at ITCTransmission, METC and ITC Midwest of $173 million, $454 million and $323 million, respectively, which resulted from the ITCTransmission and METC acquisitions and ITC Midwest’s acquisition of the IP&L transmission assets, respectively.
Intangible Assets
Pursuant to the METC acquisition in October 2006, we have identified intangible assets with finite lives derived from the portion of regulatory assets recorded on METC’s historical FERC financial statements that were not recorded on METC’s historical GAAP financial statements associated with the METC Regulatory Deferrals and


62

the METC ADIT Deferral as described in Note 7. The carrying amounts of the intangible asset for the METC Regulatory Deferrals and the METC ADIT Deferral were $14 million and $5 million (net of accumulated amortization of $26 million and $14 million), respectively, as of December 31, 2019, and $16 million and $6 million (net of accumulated amortization of $24 million and $13 million), respectively, as of December 31, 2018. The amortization periods for the METC Regulatory Deferrals and the METC ADIT Deferral are 20 years and 18 years, respectively, beginning January 1, 2007. METC earns an equity return on the remaining unamortized balance of both intangible assets and recovers the amortization expense through METC’s cost-based Formula Rate template.
ITC Great Plains has recorded intangible assets for payments made by and obligations of ITC Great Plains to certain TOs to acquire rights, which are required under the SPP tariff to designate ITC Great Plains to build, own and operate projects within the SPP region, including three regional cost sharing projects in Kansas. The carrying amount of these intangible assets was $14 million (net of accumulated amortization of $2 million) as of December 31, 2019 and 2018. The amortization period for these intangible assets is 50 years, beginning March 31, 2011.
We recognized $3 million, $4 million, and $3 million of amortization expense of our intangible assets during the years ended December 31, 2019, 2018 and 2017, respectively, recorded in depreciation and amortization on the consolidated statements of comprehensive income. We expect the annual amortization of our intangible assets that have been recorded as of December 31, 2019 to be as follows:
(In millions)
 
2020
$
4

2021
3

2022
3

2023
4

2024
3

2025 and thereafter
16

Total
$
33


10. LEASES
Operating lease costs for the year ended December 31, 2019 were $1 million. The following table shows the undiscounted future minimum lease payments under our operating leases at December 31, 2019 reconciled to the corresponding discounted lease liabilities presented in our consolidated financial statements:
Future Minimum Lease Payments
 
(in millions)
2020
 
$
1

2021
 
1

2022
 
1

2023
 
—

2024
 
1

2025 and beyond
 
—

Total lease payments
 
4

Difference between undiscounted cash flows and discounted cash flows
 
—

Present value of lease liabilities
 
4

Less: Current operating lease liabilities
 
(1
)
Noncurrent operating lease liabilities
 
$
3


Leases are presented in the consolidated statements of financial position as follows:
(in millions)
 
Classification
 
December 31, 2019
Operating Lease Assets
 
Other assets
 
$
4

Current Operating Lease Liabilities
 
Other current liabilities
 
1

Noncurrent Operating Lease Liabilities
 
Other liabilities
 
3




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Disclosures Related to Periods Prior to Adoption of the New Lease Guidance
Operating lease costs for the year ended December 31, 2018 were $1 million. Undiscounted future minimum lease payments under the operating leases at December 31, 2018 were as follows:
Future Minimum Lease Payments
 
(in millions)
2019
 
$
1

2020
 
1

2021
 
1

2022
 
—

2023 and thereafter
 
1

Total minimum lease payments
 
$
4


Supplementary Lease Information
 
 
December 31, 2019
Weighted-average remaining lease term (years)
 
4.9

Weighted-average discount rate
 
4.0
%



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11.    DEBT
Amounts of outstanding debt were classified as debt maturing within one year and long-term debt in the consolidated statements of financial position as follows:
 
December 31,
(In millions)
2019
 
2018
ITC Holdings 6.375% Senior Notes, due September 30, 2036
$
200

 
$
200

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

 
200

ITC Holdings 4.05% Senior Notes, due July 1, 2023
250

 
250

ITC Holdings 3.65% Senior Notes, due June 15, 2024
400

 
400

ITC Holdings 5.30% Senior Notes, due July 1, 2043
300

 
300

ITC Holdings 3.25% Notes, due June 30, 2026
400

 
400

ITC Holdings 2.70% Senior Notes, due November 15, 2022
500

 
500

ITC Holdings 3.35% Senior Notes, due November 15, 2027
500

 
500

ITC Holdings Term Loan Credit Agreement, due June 11, 2021
200

 
—

ITC Holdings Revolving Credit Agreement, due October 21, 2022 (b)
34

 
37

ITC Holdings Commercial Paper Program (a)
200

 
—

ITCTransmission 6.125% First Mortgage Bonds, Series C, due March 31, 2036
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 4.00% First Mortgage Bonds, Series G, due March 30, 2053
225

 
225

ITCTransmission 3.30% First Mortgage Bonds, Series H, due August 28, 2049
75

 
—

ITCTransmission Revolving Credit Agreement, due October 21, 2022 (b)
24

 
27

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 4.55% Senior Secured Notes, due January 15, 2049
50

 
—

METC 4.65% Senior Secured Notes, due July 10, 2049
50

 
—

METC Revolving Credit Agreement, due October 21, 2022 (b)
79

 
70

ITC Midwest 6.15% First Mortgage Bonds, Series A, due January 31, 2038
175

 
175

ITC Midwest 7.27% First Mortgage Bonds, Series C, due December 22, 2020 (a)
35

 
35

ITC Midwest 4.60% First Mortgage Bonds, Series D, due December 17, 2024
75

 
75

ITC Midwest 3.50% First Mortgage Bonds, Series E, due January 19, 2027
100

 
100

ITC Midwest 4.09% First Mortgage Bonds, Series F, due April 30, 2043
100

 
100

ITC Midwest 3.83% First Mortgage Bonds, Series G, due April 7, 2055
225

 
225

ITC Midwest 4.16% First Mortgage Bonds, Series H, due April 18, 2047
200

 
200

ITC Midwest 4.32% First Mortgage Bonds, Series I, due November 1, 2051
175

 
175

ITC Midwest Revolving Credit Agreement, due October 21, 2022 (b)
130

 
34

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 (b)
32

 
40

Total principal
5,844

 
5,378

Unamortized deferred financing fees and discount
(37
)
 
(40
)
Total debt
$
5,807

 
$
5,338

____________________________
(a)
As of December 31, 2019 there was $235 million of debt included within debt maturing within one year and classified as a current liability in the consolidated statements of financial position. As of December 31, 2018 we had no debt maturing within one year.
(b)
On January 10, 2020 we extended the maturity date of our revolving credit agreements to October 20, 2023. See below in “Revolving Credit Agreement Amendments” for more details.


65

The annual maturities of debt as of December 31, 2019 are as follows:
(In millions)
 
2020
$
235

2021
200

2022
799

2023
250

2024
475

2025 and thereafter
3,885

Total
$
5,844


ITC Holdings
Term Loan Credit Agreement
On June 12, 2019, ITC Holdings entered into an unsecured, unguaranteed $400 million term loan credit agreement with a maturity date of June 11, 2021, under which ITC Holdings borrowed $200 million. The proceeds were used for the early redemption of the $200 million 5.50% Senior Notes due January 15, 2020. In January 2020, ITC Holdings drew upon the remaining $200 million under the term loan credit agreement to repay outstanding commercial paper balances. The weighted-average interest rate on the borrowing outstanding under this agreement was 2.4% at December 31, 2019.
Commercial Paper Program
ITC Holdings has an ongoing commercial paper program for the issuance and sale of unsecured commercial paper in an aggregate amount not to exceed $400 million outstanding at any one time. As of December 31, 2019, ITC Holdings had $200 million of commercial paper, issued and outstanding under the program, with a weighted-average interest rate of 2.2% and weighted average remaining days to maturity of 12 days. The amount outstanding as of December 31, 2019 was classified as debt maturing within one year in the consolidated statements of financial position. As of December 31, 2018, ITC Holdings did not have any commercial paper issued or outstanding.
ITCTransmission
First Mortgage Bonds
On August 28, 2019, ITCTransmission issued $75 million aggregate principal amount of 3.30% First Mortgage Bonds, due August 28, 2049. The proceeds were used to repay existing indebtedness under the revolving credit agreement and will also be used to partially fund capital expenditures and for general corporate purposes. All of ITCTransmission’s First Mortgage bonds are issued under its First Mortgage and Deed of Trust and secured by a first mortgage lien on substantially all of its real property and tangible personal property.
On March 29, 2018, ITCTransmission issued $225 million aggregate principal amount of 4.00% First Mortgage Bonds due March 30, 2053. The proceeds were used to refinance $100 million of ITCTransmission’s 5.75% First Mortgage Bonds due April 1, 2018 and repay the existing indebtedness under ITCTransmission’s revolving credit agreement in March 2018. Proceeds were also used to repay ITCTransmission’s $50 million of borrowings under its term loan credit agreement due March 23, 2019. Remaining proceeds were used to partially fund capital expenditures and for general corporate purposes. ITCTransmission’s First Mortgage bonds were issued under its first mortgage and deed of trust and secured by a first mortgage lien on substantially all of its real property and tangible personal property.
METC
Senior Secured Notes
On January 15, 2019, METC issued $50 million of 4.55% Senior Secured Notes, due January 15, 2049. On July 10, 2019, METC issued an additional $50 million of Senior Secured Notes at 4.65% with terms and conditions identical to those of the 4.55% Senior Secured Notes except the interest rate which includes a 10 basis point premium and the due date which is 30 years from the date of the issuance. The proceeds from both issuances were used to repay borrowings under the METC revolving credit agreement, to partially fund capital expenditures


66

and for general corporate purposes. All of METC’s Senior Secured Notes are issued under its first mortgage indenture and secured by a first mortgage lien on substantially all of its real property and tangible personal property.
Term Loan Credit Agreement
On January 23, 2020, METC entered into an unsecured, unguaranteed term loan credit agreement, due January 23, 2021, under which METC borrowed the maximum of $75 million available under the agreement. The proceeds were used for general corporate purposes, primarily the repayment of borrowings under the METC revolving credit agreement.
ITC Midwest
First Mortgage Bonds
On November 1 and November 2, 2018, ITC Midwest issued an aggregate of $175 million of 4.32% First Mortgage Bonds due November 1, 2051. The proceeds were used to partially repay existing indebtedness under the ITC Midwest revolving credit agreement, partially fund capital expenditures and for general corporate purposes. ITC Midwest’s First Mortgage Bonds were issued under its first mortgage and deed of trust and secured by a first mortgage lien on substantially all of our real property and tangible personal property.
Derivative Instruments and Hedging Activities
We have entered into interest rate swaps to manage interest rate risk associated with the anticipated refinancing of the $400 million term loan at ITC Holdings with a maturity date of June 11, 2021. At December 31, 2019, ITC Holdings had the following interest rate swaps:
Interest Rate Swaps
(in millions, except percentages)
 
Notional Amount
 
Weighted Average Fixed Rate
 
Original Term
 
Effective Date
July 2019 swap
 
$
50

 
1.816
%
 
5 years
 
November 2020
August 2019 swap
 
50

 
1.488
%
 
5 years
 
November 2020
October 2019 swaps
 
100

 
1.288
%
 
5 years
 
November 2020
Total
 
$
200

 
 
 
 
 
 

The 5-year term interest rate swaps call for ITC Holdings to receive interest quarterly at a variable rate equal to LIBOR and to pay interest semi-annually at various fixed rates effective for the 5-year period beginning November 15, 2020. The agreements include a mandatory early termination provision and will be terminated no later than the effective date of the interest rate swaps of November 15, 2020. The interest rate swaps do not contain credit-risk-related contingent features. The interest rate swaps are highly effective at offsetting changes in the forecasted interest cash flows associated with the debt issuance, resulting from changes in benchmark interest rates from the trade date of the interest rate swaps to the issuance date of the debt obligation.
In January 2020, ITC Holdings entered into three 5-year interest rate swap contracts with fixed rates of 1.551%, 1.447% and 1.314%, and each with a notional amount of $63 million and effective date of October 1, 2020. The interest rate swaps also manages interest rate risk associated with the refinancing of the $400 million term loan at ITC Holdings. The agreements include a mandatory early termination provision and will be terminated no later than the effective date of the interest rate swaps of October 1, 2020. The interest rate swaps are expected to be highly effective at offsetting changes in the fair value of the forecasted interest cash flows associated with the debt issuance, resulting from changes in benchmark interest rates from the trade date of the interest rate swaps to the issuance date of the debt obligation.
The interest rate swaps qualify for cash flow hedge accounting treatment, whereby any gain or loss recognized from the trade date to the effective date is recorded net of tax in AOCI. As of December 31, 2019, the fair value of the derivative instruments of $3 million was recorded in other current assets in the consolidated statements of financial position. Refer to Note 14 for additional fair value information.


67

Revolving Credit Agreements
At December 31, 2019, ITC Holdings and certain of its Regulated Operating Subsidiaries had the following unsecured revolving credit facilities available:
(In millions, except percentages)
Total
Available
Capacity
 
Outstanding
Balance (a)
 
Unused
Capacity
 
Weighted Average
Interest Rate on
Outstanding Balance (b)
 
Commitment
Fee Rate (c)
ITC Holdings
$
400

 
$
34

 
$
366

(d)
 
2.9%
 
0.175
%
ITCTransmission
100

 
24

 
76

 
 
2.6%
 
0.10
%
METC
100

 
79

 
21

 
 
2.6%
 
0.10
%
ITC Midwest
225

 
130

 
95

 
 
2.6%
 
0.10
%
ITC Great Plains
75

 
32

 
43

 
 
2.6%
 
0.10
%
Total
$
900

 
$
299

 
$
601

 
 
 
 
 
____________________________
(a)
Included within long-term debt in the consolidated statements of financial position.
(b)
Interest charged on borrowings depends on the variable rate structure we elected at the time of each borrowing.
(c)
Calculation based on the average daily unused commitments, subject to adjustment based on the borrower’s credit rating.
(d)
ITC Holdings’ revolving credit agreement may be used for general corporate purposes, including to repay commercial paper issued pursuant to the commercial paper program described above, if necessary. While outstanding commercial paper does not reduce available capacity under ITC Holdings’ revolving credit agreement, the unused capacity under this agreement adjusted for the commercial paper outstanding was $166 million as of December 31, 2019.
Revolving Credit Agreement Amendments
On January 10, 2020, ITC Holdings, ITCTransmission, METC, ITC Midwest and ITC Great Plains amended and restated their respective revolving credit agreements each dated October 23, 2017. The amendments extend the maturity date of the revolving credit agreements from October 2022 to October 2023. The determination of the applicable interest rates and commitment fee rates in the new agreements is consistent with the previous agreements as described above and remain subject to adjustment based on the borrower’s credit rating.


68

12.    INCOME TAXES
Our effective tax rate varied from the statutory federal income tax rate due to differences between the book and tax treatment of various transactions as follows:
 
Year Ended December 31,
(In millions)
2019
 
2018
 
2017
Income tax expense at federal statutory rate (a)
$
118

 
$
93

 
$
180

State income taxes (net of federal benefit) (b)
22

 
31

 
16

AFUDC equity
(5
)
 
(6
)
 
(10
)
Revaluation of deferred federal income taxes (c)
—

 
(2
)
 
8

Other, net (d)
(3
)
 
(5
)
 
2

Total income tax provision
$
132

 
$
111

 
$
196


____________________________
(a)
The federal statutory rate is 21% for 2019 and 2018, and 35% for 2017.
(b)
Amounts for the years ended December 31, 2019 and 2018 includes $1 million and $6 million, respectively, related to the remeasurement of Iowa NOLs due to the rate change from 12.0% to 9.8% effective January 1, 2021. Amount for the year ended December 31, 2017 includes income tax benefits of $3 million related to the revaluation of state deferred tax assets and liabilities for the net of federal benefit impact of the TCJA.
(c)
Amount for the year ended December 31, 2018 represents the change in estimate related to the TCJA remeasurement recorded in 2017 based on the ITC Holdings’ 2017 Federal Tax return filed. Amount for the year ended December 31, 2017 represents income tax expense related to the revaluation of federal deferred tax assets and liabilities as a result of the TCJA.
(d)
Amount for the year ended December 31, 2017 includes income tax expense of $1 million related to the establishment of a valuation allowance for the portion of a capital loss expected to not be utilized before expiration.
Components of the income tax provision were as follows:
 
Year Ended December 31,
(In millions)
2019
 
2018
 
2017
Current income tax (benefit) expense
$
(3
)
 
$
4

 
$
1

Deferred income tax expense (a)
135

 
107

 
195

Total income tax provision
$
132

 
$
111

 
$
196


____________________________
(a)
Amount for the year ended December 31, 2017 includes income tax expense of $5 million related to the net revaluation of federal and state deferred tax assets and liabilities at ITC Holdings as a result of the TCJA.
Deferred tax assets and liabilities are recognized for the estimated future tax effect of temporary differences between the tax basis of assets or liabilities and the reported amounts in the consolidated financial statements.
The TCJA resulted in significant changes to the Internal Revenue Code including a reduction in the U.S. federal corporate income tax rate from 35% to 21% effective for tax years beginning after 2017. For additional information on the impacts of tax reform, see Note 7. During the year ended December 31, 2018, Iowa enacted a reduction in corporate statutory income tax rates from 12.0% to 9.8%, effective January 1, 2021. Based upon the future change in rate, we revalued the Iowa NOL at ITC Holdings. As a result, additional income tax expense was recorded for the year ended December 31, 2018 compared to the same period in 2019. For the years ended December 31, 2019 and 2018, our effective tax rates were 23.6% and 25.2%, respectively.


69

Deferred income tax assets (liabilities) consisted of the following:
 
December 31,
(In millions)
2019
 
2018
Property, plant and equipment
$
(1,071
)
 
$
(884
)
Federal income tax NOLs and other credits
117

 
47

METC regulatory deferral (a)
(5
)
 
(6
)
Acquisition adjustments — ADIT deferrals (a)
(7
)
 
(8
)
Goodwill
(133
)
 
(128
)
Refund liabilities (a)
19

 
40

Regulatory liability gross up — TCJA
134

 
138

Pension and postretirement liabilities
18

 
18

State income tax NOLs (net of federal benefit)
52

 
43

True-up adjustment principal & interest
(1
)
 
14

Other, net
4

 
5

Net deferred tax liabilities
$
(873
)
 
$
(721
)
Gross deferred income tax liabilities
$
(1,233
)
 
$
(1,040
)
Gross deferred income tax assets
360

 
319

Net deferred tax liabilities
$
(873
)
 
$
(721
)
____________________________
(a)
Described in Note 7.
We have federal income tax NOLs as of December 31, 2019. We expect to use our NOLs prior to their expirations starting in 2036. We also have state income tax NOLs as of December 31, 2019, all of which we expect to use prior to their expiration starting in 2022.
13.    RETIREMENT BENEFITS AND ASSETS HELD IN TRUST
Pension and Postretirement Plan Benefits
We have a qualified defined benefit pension plan (“retirement plan”) for eligible employees, comprised of a traditional final average pay plan and a cash balance plan. The traditional final average pay plan is noncontributory, covers select employees, and provides retirement benefits based on years of benefit service, average final compensation, and age at retirement. The cash balance plan is also noncontributory, covers substantially all employees, and provides retirement benefits based on eligible compensation and interest credits. Our funding practice for the retirement plan is generally to fund the annual net pension cost, though we may contribute additional amounts as necessary to meet the minimum funding requirements of the Employee Retirement Income Security Act of 1974, or as we deem appropriate. We made contributions of $4 million to the retirement plan in each of 2019, 2018, and 2017. We expect to contribute $4 million to the retirement plan in 2020.
We also have two supplemental nonqualified, noncontributory, defined benefit pension plans for selected management employees (the “supplemental benefit plans” and collectively with the retirement plan, the “pension plans”). The supplemental benefit plans provide for benefits that supplement those provided by the retirement plan. The obligations under these supplemental benefit plans are included in the pension benefit obligation calculations below. The investments held in trust for the supplemental benefit plans of $54 million and $53 million at December 31, 2019 and 2018, respectively, are not included in the plan asset amounts presented throughout this footnote, but are included in other assets on our consolidated statements of financial position. For the years ended December 31, 2019, 2018, and 2017, we contributed $1 million, $3 million, and $14 million, respectively, to these supplemental benefit plans.
We provide certain postretirement health care, dental, and life insurance benefits for eligible employees (the “postretirement benefit plan”). We contributed $9 million, $9 million, and $8 million to the postretirement benefit plan in 2019, 2018, and 2017, respectively. We expect to contribute $11 million to the postretirement benefit plan in 2020.


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Net periodic benefit costs by component for the pension plans and postretirement benefit plan were as follows:
 
Pension Plans
 
Postretirement Benefit Plan
 
Years Ended December 31,
 
 Years Ended December 31,
(In millions)
2019
 
2018
 
2017
 
2019
 
2018
 
2017
Service cost
$
7

 
$
7

 
$
6

 
$
9

 
$
10

 
$
8

Interest cost
5

 
4

 
4

 
4

 
3

 
3

Expected return on plan assets
(5
)
 
(5
)
 
(4
)
 
(4
)
 
(3
)
 
(2
)
Amortization of unrecognized loss
1

 
1

 
1

 
—

 
—

 
—

Net benefit cost
$
8

 
$
7

 
$
7

 
$
9

 
$
10

 
$
9


The following table reconciles the obligations, assets, and funded status of the pension plans and postretirement benefit plan as well as the presentation of the funded status of the plans in the consolidated statements of financial position:
 
Pension Plans
 
Postretirement Benefit Plan
 
December 31,
 
December 31,
(In millions)
2019
 
2018
 
2019
 
2018
Change in Benefit Obligation:
 
 
 
 
 
 
 
Beginning projected benefit obligation
$
(123
)
 
$
(127
)
 
$
(90
)
 
$
(86
)
Service cost
(7
)
 
(7
)
 
(9
)
 
(10
)
Interest cost
(5
)
 
(4
)
 
(4
)
 
(3
)
Actuarial net gain (loss)
(12
)
 
9

 
(11
)
 
8

Benefits paid
6

 
6

 
1

 
1

Ending projected benefit obligation
(141
)
 
(123
)
 
(113
)
 
(90
)
Change in Plan Assets:
 
 
 
 
 
 
 
Beginning plan assets at fair value
73

 
75

 
72

 
66

Actual return on plan assets
16

 
(3
)
 
15

 
(2
)
Employer contributions
4

 
4

 
9

 
9

Benefits paid
(2
)
 
(3
)
 
(1
)
 
(1
)
Ending plan assets at fair value
91

 
73

 
95

 
72

Funded status, underfunded
$
(50
)
 
$
(50
)
 
$
(18
)
 
$
(18
)
Accumulated benefit obligation:


 


 
 
 
 
Retirement plan
$
(78
)
 
$
(67
)
 
N/A

 
N/A

Supplemental benefit plans
(57
)
 
(52
)
 
N/A

 
N/A

Total accumulated benefit obligation
$
(135
)
 
$
(119
)
 
$
—

 
$
—

Amounts recorded as:
 
 


 
 
 
 
Funded Status:
 
 
 
 
 
 
 
Accrued pension and postretirement liabilities
$
(55
)
 
$
(50
)
 
$
(18
)
 
$
(18
)
Other non-current assets
9

 
4

 
N/A

 
N/A

Other current liabilities
(4
)
 
(4
)
 
N/A

 
N/A

Total
$
(50
)
 
$
(50
)
 
$
(18
)
 
$
(18
)
Unrecognized Amounts in Non-current Regulatory Assets:
 
 
 
 
 
 
 
Net actuarial loss
$
24

 
$
24

 
$
1

 
$
1

Total
$
24

 
$
24

 
$
1

 
$
1


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


71

accumulated benefit obligation for the postretirement benefit plan as of December 31, 2019 and 2018 does not reflect the potential receipt of any subsidies under the Medicare Prescription Drug, Improvement and Modernization Act of 2003.
The net actuarial gain for the year ended December 31, 2018 and the net actuarial loss for the year ended December 31, 2019 within the change in benefit obligation are primarily the result of fluctuations in the discount rates for both the Pension Plans and Postretirement Benefit Plan.
The combined projected benefit obligation and fair value of plan assets for those plans in which the projected benefit obligation is in excess of the fair value of plan assets are as follows:
 
Pension Plans
 
December 31,
(In millions)
2019
 
2018
Projected benefit obligation
$
(59
)
 
$
(54
)
Fair value of plan assets (a)
—

 
—

____________________________
(a)
The investments held in trust for our supplemental benefit plans are not included in the plan asset amounts presented herein, but are included in Other Assets on our consolidated statements of financial position.
The combined accumulated benefit obligation and fair value of plan assets for those plans in which the accumulated benefit obligation is in excess of the fair value of plan assets are as follows:
 
Pension Plans
 
December 31,
(In millions)
2019
 
2018
Accumulated benefit obligation
$
(57
)
 
$
(52
)
Fair value of plan assets (a)
—

 
—

____________________________
(a)
The investments held in trust for our supplemental benefit plans are not included in the plan asset amounts presented herein, but are included in Other Assets on our consolidated statements of financial position.
Actuarial assumptions used to determine the benefit obligations for the pension plans and postretirement benefit plan are as follows:
 
Pension Plans
 
Postretirement Benefit Plan
 
December 31,
 
December 31,
 
2019
 
2018
 
2017
 
2019
 
2018
 
2017
Weighted average discount rate
3.27%
 
4.28%
 
3.57%
 
3.61%
 
4.47%
 
3.75%
Weighted average interest crediting rate
4.00%
 
4.50%
 
4.50%
 
N/A
 
N/A
 
N/A
Annual rate of salary increases
4.00%
 
4.00%
 
4.00%
 
4.00%
 
4.00%
 
4.00%
Health care cost trend rate
N/A
 
N/A
 
N/A
 
6.25%
 
6.50%
 
6.75%
Ultimate health care cost trend rate
N/A
 
N/A
 
N/A
 
5.00%
 
5.00%
 
5.00%
Year that the ultimate trend rate is reached
N/A
 
N/A
 
N/A
 
2025
 
2025
 
2025
Annual rate of increase in dental benefit costs
N/A
 
N/A
 
N/A
 
4.50%
 
4.50%
 
4.50%



72

Actuarial assumptions used to determine the benefit cost for the pension plans and postretirement benefit plan are as follows:
 
Pension Plans
 
Postretirement Benefit Plan
 
Years Ended December 31,
 
Years Ended December 31,
 
2019
 
2018
 
2017
 
2019
 
2018
 
2017
Weighted average discount rate — service cost
4.42%
 
3.70%
 
4.20%
 
4.58%
 
3.80%
 
4.35%
Weighted average discount rate — interest cost
3.99%
 
3.26%
 
3.45%
 
4.28%
 
3.58%
 
3.98%
Weighted average interest crediting rate
4.50%
 
4.50%
 
4.50%
 
N/A
 
N/A
 
N/A
Annual rate of salary increases
4.00%
 
4.00%
 
4.00%
 
4.00%
 
4.00%
 
4.00%
Health care cost trend rate
N/A
 
N/A
 
N/A
 
6.50%
 
6.75%
 
7.00%
Ultimate health care cost trend rate
N/A
 
N/A
 
N/A
 
5.00%
 
5.00%
 
5.00%
Year that the ultimate trend rate is reached
N/A
 
N/A
 
N/A
 
2025
 
2025
 
2022
Expected long-term rate of return on plan assets
6.60%
 
6.40%
 
6.20%
 
5.00%
 
4.90%
 
4.70%

At December 31, 2019, the projected benefit payments for the pension plans and postretirement benefit plan calculated using the same assumptions as those used to calculate the benefit obligations described above are as follows:
(In millions)
Pension Plans
 
Postretirement Benefit Plan
2020
$
8

 
$
1

2021
8

 
2

2022
8

 
2

2023
8

 
2

2024
9

 
3

2025 through 2029
56

 
21


Investment Objectives and Fair Value Measurement
The general investment objectives of the retirement plan and postretirement benefit plan include maximizing the return within reasonable and prudent levels of risk and controlling administrative and management costs. Investment decisions are made by our retirement benefits board as delegated by our board of directors. Equity investments may include various types of U.S. and international equity securities, such as large-cap, mid-cap, and small-cap stocks. Fixed income investments may include cash and short-term instruments, U.S. Government securities, corporate bonds, mortgages, and other fixed income investments. No investments are prohibited for use in the retirement plan or postretirement benefit plan, including derivatives, but our exposure to derivatives currently is not material. We intend that the long-term capital growth of the retirement and postretirement benefit plans, together with employer contributions, will provide for the payment of the benefit obligations.
As of December 31, 2019 and 2018, the plan assets of the retirement plan and postretirement benefit plan consisted of the following assets by category:
 
Target Allocation
 
Pension Plans
 
Postretirement Benefit Plan
Asset Category
2019
 
2019
 
2018
 
2019
 
2018
Fixed income securities
50.0
%
 
50.0
%
 
48.6
%
 
50.0
%
 
48.4
%
Equity securities
50.0
%
 
50.0
%
 
51.4
%
 
50.0
%
 
51.6
%
Total
100.0
%
 
100.0
%
 
100.0
%
 
100.0
%
 
100.0
%

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


73

develop its own assumptions. Changes in economic conditions or model-based valuation techniques may require the transfer of financial instruments from one fair value level to another. In such instances, the transfer is reported at the beginning of the reporting period. For the years ended December 31, 2019 and 2018, there were no transfers between levels.
The fair value measurement of the retirement plan assets was as follows:
 
December 31, 2019
 
December 31, 2018
 
Fair Value Measurements at Reporting Date Using
 
Fair Value Measurements at Reporting Date Using
(In millions)
Level 1
 
Level 2
 
Level 3
 
Level 1
 
Level 2
 
Level 3
Financial assets measured on a recurring basis:
 
 
 
 
 
 
 
 
 
 
 
Mutual funds — U.S. equity securities
$
36

 
$
—

 
$
—

 
$
30

 
$
—

 
$
—

Mutual funds — international equity securities
9

 
—

 
—

 
7

 
—

 
—

Mutual funds — fixed income securities
46

 
—

 
—

 
36

 
—

 
—

Total
$
91

 
$
—

 
$
—

 
$
73

 
$
—

 
$
—

The fair value measurement of the postretirement benefit plan assets was as follows:
 
December 31, 2019
 
December 31, 2018
 
Fair Value Measurements at Reporting Date Using
 
Fair Value Measurements at Reporting Date Using
(In millions)
Level 1
 
Level 2
 
Level 3
 
Level 1
 
Level 2
 
Level 3
Financial assets measured on a recurring basis:
 
 
 
 
 
 
 
 
 
 
 
Mutual funds — U.S. equity securities
$
45

 
$
—

 
$
—

 
$
36

 
$
—

 
$
—

Mutual funds — international equity securities
2

 
—

 
—

 
1

 
—

 
—

Mutual funds — fixed income securities
48

 
—

 
—

 
35

 
—

 
—

Total
$
95

 
$
—

 
$
—

 
$
72

 
$
—

 
$
—

The mutual funds consist primarily of publicly traded mutual funds and are recorded at fair value based on observable trades for identical securities in an active market.
Defined Contribution Plan
We also sponsor a defined contribution retirement savings plan. Participation in this plan is available to substantially all employees. We match employee contributions up to certain predefined limits based upon eligible compensation and the employee’s contribution rate. The cost of this plan was $5 million in each of 2019, 2018, and 2017.
14.    FAIR VALUE MEASUREMENTS
The measurement of fair value is based on a three-tier hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. Changes in economic conditions or model-based valuation techniques may require the transfer of financial instruments from one fair value level to another. In such instances, the transfer is reported at the beginning of the reporting period. For the years ended December 31, 2019 and 2018, there were no transfers between levels.


74

Our assets measured at fair value subject to the three-tier hierarchy at December 31, 2019, were as follows:
 
Fair Value Measurements at Reporting Date Using
 
Quoted Prices in
Active Markets for
Identical Assets
 
Significant
Other Observable
Inputs
 
Significant
Unobservable
Inputs
(in millions)
(Level 1)
 
(Level 2)
 
(Level 3)
Financial assets measured on a recurring basis:
 
 
 
 
 
Mutual funds — fixed income securities
$
50

 
$
—

 
$
—

Mutual funds — equity securities
8

 
—

 
—

Interest rate swap derivatives
—

 
3

 
—

Total
$
58

 
$
3

 
$
—

Our assets measured at fair value subject to the three-tier hierarchy at December 31, 2018, were as follows:
 
Fair Value Measurements at Reporting Date Using
 
Quoted Prices in
Active Markets for
Identical Assets
 
Significant
Other Observable
Inputs
 
Significant
Unobservable
Inputs
(in millions)
(Level 1)
 
(Level 2)
 
(Level 3)
Financial assets measured on a recurring basis:
 
 
 
 
 
Cash equivalents
$
1

 
$
—

 
$
—

Mutual funds — fixed income securities
49

 
—

 
—

Mutual funds — equity securities
5

 
—

 
—

Total
$
55

 
$
—

 
$
—


As of December 31, 2019 and 2018, we held certain assets that are required to be measured at fair value on a recurring basis. The assets included in the table consist of investments recorded within cash and cash equivalents and other long-term assets, including investments held in a trust associated with our supplemental benefit plans described in Note 13. The mutual funds we own are publicly traded and are recorded at fair value based on observable trades for identical securities in an active market. Changes in the observed trading prices and liquidity of money market funds are monitored as additional support for determining fair value. Gains and losses for all mutual fund investments are recorded in earnings.
The assets related to derivatives consist of interest rate swaps discussed in Note 11. The fair value of our interest rate swap derivatives is determined based on a DCF method using LIBOR swap rates, which are observable at commonly quoted intervals.
We also held non-financial assets that are required to be measured at fair value on a non-recurring basis. These consist of goodwill and intangible assets. We did not record any impairment charges on long-lived assets and no other significant events occurred requiring non-financial assets and liabilities to be measured at fair value (subsequent to initial recognition) during the years ended December 31, 2019 and 2018. Refer to Note 9 for additional information on our goodwill and intangible assets.
Fair Value of Financial Assets and Liabilities
Fixed Rate Debt
Based on the borrowing rates obtained from third party lending institutions currently available for bank loans with similar terms and average maturities from active markets, the fair value of our consolidated long-term debt and debt maturing within one year, excluding revolving and term loan credit agreements and commercial paper, was $5,672 million and $5,186 million at December 31, 2019 and 2018, respectively. These fair values represent Level 2 under the three-tier hierarchy described above. The total book value of our consolidated long-term debt and debt maturing within one year, net of discount and deferred financing fees and excluding revolving and term loan credit agreements and commercial paper, was $5,108 million and $5,130 million at December 31, 2019 and 2018, respectively.


75

Revolving and Term Loan Credit Agreements
At December 31, 2019 and 2018, we had a consolidated total of $499 million and $208 million, respectively, outstanding under our revolving and term loan credit agreements, which are variable rate loans. The fair value of these loans approximates book value based on the borrowing rates currently available for variable rate loans obtained from third party lending institutions. These fair values represent Level 2 under the three-tier hierarchy described above.
Other Financial Instruments
The carrying value of other financial instruments included in current assets and current liabilities, including cash and cash equivalents, special deposits and commercial paper, approximates their fair value due to the short-term nature of these instruments.
15.    STOCKHOLDER'S EQUITY
Accumulated Other Comprehensive Income
The following table provides the components of changes in AOCI:
 
Year Ended December 31,
(In millions)
2019
 
2018
 
2017
Balance at the beginning of period
$
4

 
$
2

 
$
2

Reclassification of deferred tax effects on interest rate cash flow hedges stranded in AOCI, subject to the TCJA, into retained earnings
—

 
1

 
—

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

 
1

 
1

Gain (loss) on interest rate swaps relating to interest rate cash flow hedges (net of tax of $1 for each of the years ended December 31, 2019 and 2017)
2

 
—

 
(1
)
Total other comprehensive income (loss), net of tax
3

 
1

 
—

Balance at the end of period
$
7

 
$
4

 
$
2


____________________________
(a)
The reclassification of the net loss relating to interest rate cash flow hedges is reported in interest expense on a pre-tax basis.
The amount of net loss relating to interest rate cash flow hedges to be reclassified from AOCI to earnings for the 12-month period ending December 31, 2020 is expected to be approximately $1 million (net of tax of less than $1 million). The reclassification is reported in interest expense on a pre-tax basis.


76

16.    SHARE-BASED COMPENSATION AND EMPLOYEE SHARE PURCHASE PLAN
We recorded share-based compensation costs as follows:
 
Year Ended December 31,
(In millions)
2019
 
2018
 
2017
Operation and maintenance expenses
$
2

 
$
1

 
$
1

General and administrative expenses
30

 
7

 
3

Amounts capitalized to property, plant and equipment
8

 
3

 
1

Total share-based compensation costs
$
40

 
$
11

 
$
5

Total tax benefit recognized in the consolidated statements of comprehensive income
$
8

 
$
4

 
$
1


2017 Omnibus Plan
Under the 2017 Omnibus Plan, we may grant long-term incentive awards of PBUs and SBUs to employees, including executive officers, of ITC Holdings and its subsidiaries. Each PBU and SBU granted will be valued based on one share of Fortis common stock traded on the Toronto Stock Exchange, converted to U.S. dollars and settled only in cash. The awards vest on the date specified in a particular grant agreement, provided the service and performance criteria, as applicable, are satisfied.
Performance-Based Units
The PBUs are classified as liability awards based on the cash settlement feature. The PBUs are measured at fair value at the end of each reporting period, which will fluctuate based on the price of Fortis common stock and the level of achievement of the financial performance criteria, including a market condition and a performance condition. The payout may range from 0% - 200% of the target award, depending on actual performance relative to the performance criteria. The PBUs earn dividend equivalents which are also re-measured consistent with the target award and settled in cash at the end of the vesting period. The granted awards and related dividend equivalents have no shareholder rights. PBUs that were granted pursuant to the 2017 Omnibus Plan generally vest on the third December 31st following the grant date, provided the service and performance criteria are satisfied and will be settled during the subsequent quarter.
The following table shows the changes in PBUs during the year ended December 31, 2019:
 
Number of
 
Performance
 
Based Units
PBUs at December 31, 2018
637,551

Granted
380,305

Forfeited
(41,628
)
PBUs at December 31, 2019
976,228


The following table presents the classification in the consolidated statements of financial position of obligations related to outstanding PBUs not yet settled:

December 31,
(In millions)
2019

2018
Accrued compensation
$
17


$
—

Other long-term liabilities
19


7

Total
$
36


$
7


The aggregate fair value of PBUs as of December 31, 2019 and 2018 was $54 million and $18 million, respectively. At December 31, 2019, $18 million of total unrecognized compensation cost related to PBUs not yet vested is expected to be recognized over the remaining weighted-average period of 1.7 years.
Service-Based Units
The SBUs are classified as liability awards based on the cash settlement feature. The SBUs are measured at fair value at the end of each reporting period, which will fluctuate based on the price of Fortis common stock. The SBUs


77

earn dividend equivalents which are also re-measured based on the price of Fortis common stock and settled in cash at the end of the vesting period. The granted awards and related dividend equivalents have no shareholder rights. SBUs that were granted pursuant to the 2017 Omnibus Plan generally vest on the third December 31st following the grant date, provided the service criterion is satisfied and vested awards will be settled during the subsequent quarter.
The following table shows the changes in SBUs during the year ended December 31, 2019:
 
Number of
 
Service
 
Based Units
SBUs at December 31, 2018
488,903

Granted
294,539

Vested and paid out
(2,479
)
Forfeited
(35,713
)
SBUs at December 31, 2019
745,250


The following table presents the classification in the consolidated statements of financial position of obligations related to outstanding SBUs not yet settled:
 
December 31,
(In millions)
2019
 
2018
Accrued compensation
$
10

 
$
—

Other long-term liabilities
10

 
8

Total
$
20

 
$
8


The aggregate fair value of SBUs as of December 31, 2019 and 2018 was $30 million and $17 million, respectively. At December 31, 2019, $10 million of the total unrecognized compensation cost related to SBUs not yet vested is expected to be recognized over the remaining weighted-average period of 1.7 years.
Employee Share Purchase Plan
Effective May 4, 2017, Fortis adopted the ESPP, which enables ITC employees to purchase common shares of Fortis stock. The ESPP allows eligible employees to contribute during any investment period between 1% and 10% of their annual base pay, with an employee’s aggregate contribution for the calendar year not to exceed 10% of annual base pay for the year. Employee contributions are made at the beginning of each quarterly investment period in either a lump sum or by means of a loan from ITC Holdings, which is repayable over 52 weeks from payroll deductions (or earlier upon certain events) and secured by a pledge on the related purchased shares. ITC Holdings contributes as additional compensation an amount equal to 10% of an employee’s contribution up to a maximum annual contribution of 1% of an employee’s annual base pay and an amount equal to 10% of all dividends payable by Fortis on the Fortis shares allocated to an employee’s ESPP account. All amounts contributed to the ESPP by employees and ITC Holdings are used to purchase Fortis common shares from Fortis or in the market concurrent with the quarterly dividend payment dates of March 1, June 1, September 1 and December 1. ITC Holdings implemented the ESPP during the second quarter of 2017. The cost of ITC Holdings’ contribution for the years ended December 31, 2019, 2018, and 2017 was less than $1 million, respectively.
17.    JOINTLY OWNED UTILITY PLANT/COORDINATED SERVICES
Certain of our Regulated Operating Subsidiaries have agreements with other utilities for the joint ownership of substation assets and transmission lines. We account for these jointly owned assets by recording property, plant and equipment for our percentage of ownership interest. Various agreements provide the authority for construction of capital improvements and the operating costs associated with the substations and lines. Generally, each party is responsible for the capital, operation and maintenance and other costs of these jointly owned facilities based upon each participant’s undivided ownership interest, and each participant is responsible for providing its own financing. Our participating share of expenses associated with these jointly held assets are primarily recorded within operation and maintenance expenses on our consolidated statements of comprehensive income.


78

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

Net Investments (a)
(In millions)
Substations
 
Lines
 
Other
ITCTransmission (b)
$
—

 
$
29

 
$
—

METC (c)
16

 
41

 
—

ITC Midwest (d)
43

 
37

 
—

ITC Great Plains (e)
10

 
23

 
—

Total
$
69

 
$
130

 
$
—

____________________________
(a)
Amount represents our investment in jointly held plant, which has been reduced by the ownership interest amounts of other parties.
(b)
ITCTransmission has joint ownership in two 345 kV transmission lines with a municipal power agency that has a 50.4% ownership interest in the transmission lines. An Ownership and Operating Agreement with the municipal power agency provides ITCTransmission with authority for construction of capital improvements and for the operation and management of the transmission lines. The municipal power agency is responsible for the capital and operation and maintenance costs allocable to their ownership interest.
(c)
METC has joint sharing of several assets within various substations with Consumers Energy, other municipal distribution systems and other generators. The rights, responsibilities and obligations for these jointly owned assets are documented in the Amended and Restated Distribution — Transmission Interconnection Agreement with Consumers Energy and in numerous interconnection facilities agreements with various municipalities and other generators. In addition, other municipal power agencies and cooperatives have an ownership interest in several METC 345 kV transmission lines. This ownership entitles these municipal power agencies and cooperatives to approximately 608 MW of network transmission service from the METC transmission system. As of December 31, 2019, METC’s ownership percentages for jointly owned substation facilities and lines ranged from less than 1.0% to 92.0% and 1.0% to 41.9%, respectively.
(d)
ITC Midwest has joint sharing of several substations and transmission lines with various parties. ITC Midwest’s ownership percentages for jointly owned substation facilities and lines ranged from 28.0% to 80.0% and 11.0% to 80.0%, respectively, as of December 31, 2019.
(e)
In 2014, ITC Great Plains entered into a joint ownership agreement with an electric cooperative that has a 49.0% ownership interest in a transmission project. ITC Great Plains will construct and operate the project and the electric cooperative will be responsible for their ownership percentage of capital and operation and maintenance costs. As of December 31, 2019, ITC Great Plains’ ownership percentage in the project was 51.0%.
18.    RELATED PARTY TRANSACTIONS
Intercompany Receivables and Payables
ITC Holdings may incur charges from Fortis and other subsidiaries of Fortis that are not subsidiaries of ITC Holdings for general corporate expenses incurred. In addition, ITC Holdings may perform additional services for, or receive additional services from, Fortis and such subsidiaries. These transactions are in the normal course of business and payments for these services are settled through accounts receivable and accounts payable, as necessary. We had intercompany receivables from Fortis and such subsidiaries of less than $1 million at December 31, 2019 and December 31, 2018 and intercompany payables to Fortis and such subsidiaries of less than $1 million at December 31, 2019 and December 31, 2018.
Related party charges for corporate expenses from Fortis and such subsidiaries are recorded in general and administrative expense. ITC Holdings had such expense for the year ended December 31, 2019 of $10 million and for each of the years ended December 31, 2018 and 2017 of $8 million. Related party billings for services to Fortis and other subsidiaries recorded as an offset to general and administrative expenses for ITC Holdings were less than $1 million for each of the years ended December 31, 2019 and 2018, and $1 million for the year ended December 31, 2017.


79

Dividends
We paid dividends of $250 million, $200 million and $300 million during the years ended December 31, 2019, 2018 and 2017, respectively, to ITC Investment Holdings. ITC Holdings also paid dividends of $83 million to ITC Investment Holdings in January of 2020.
Intercompany Tax Sharing Agreement
We are organized as a corporation for tax purposes and subject to a tax sharing agreement as a wholly-owned subsidiary of ITC Investment Holdings. Additionally, we record income taxes based on our separate company tax position and make or receive tax-related payments with ITC Investment Holdings. We did not make or receive any tax-related payments during the year ended December 31, 2019. During the year ended December 31, 2019, we received a payment of $2 million from FortisUS for a tax refund that originated prior to establishing the tax sharing agreement.
19.    COMMITMENTS AND CONTINGENT LIABILITIES
Environmental Matters
We are subject to federal, state and local environmental laws and regulations, which impose limitations on the discharge of pollutants into the environment, establish standards for the management, treatment, storage, transportation and disposal of solid and hazardous wastes and hazardous materials, and impose obligations to investigate and remediate contamination in certain circumstances. Liabilities relating to investigation and remediation of contamination, as well as other liabilities concerning hazardous materials or contamination, such as claims for personal injury or property damage, may arise at many locations, including formerly owned or operated properties and sites where wastes have been treated or disposed of, as well as properties currently owned or operated by us. Such liabilities may arise even where the contamination does not result from noncompliance with applicable environmental laws. Under some environmental laws, such liabilities may also be joint and several, meaning that a party can be held responsible for more than its share of the liability involved, or even the entire share. Although environmental requirements generally have become more stringent and compliance with those requirements more expensive, we are not aware of any specific developments that would increase our costs for such compliance in a manner that would be expected to have a material adverse effect on our results of operations, financial condition or liquidity.
Our assets and operations also involve the use of materials classified as hazardous, toxic or otherwise dangerous. Many of the properties that we own or operate have been used for many years and include older facilities and equipment that may be more likely than newer ones to contain or be made from such materials. Some of these properties include aboveground or underground storage tanks and associated piping. Some of them also include large electrical equipment filled with mineral oil, which may contain or previously have contained PCBs. Our facilities and equipment are often situated on or near property owned by others so that, if they are the source of contamination, others’ property may be affected. For example, aboveground and underground transmission lines sometimes traverse properties that we do not own and transmission assets that we own or operate are sometimes commingled at our transmission stations with distribution assets owned or operated by our transmission customers.
Some properties in which we have an ownership interest or at which we operate are, or are suspected of being, affected by environmental contamination. We are not aware of any pending or threatened claims against us with respect to environmental contamination relating to these properties, or of any investigation or remediation of contamination at these properties, that entail costs likely to materially affect us. Some facilities and properties are located near environmentally sensitive areas such as wetlands.
Litigation
We are involved in certain legal proceedings before various courts, governmental agencies and mediation panels concerning matters arising in the ordinary course of business. These proceedings include certain contract disputes, eminent domain and vegetation management activities, regulatory matters and pending judicial matters. We cannot predict the final disposition of such proceedings. We regularly review legal matters and record provisions for claims that are considered probable of loss.
Rate of Return on Equity Complaints
Two complaints were filed with the FERC by combinations of consumer advocates, consumer groups, municipal parties and other parties challenging the base ROE in MISO. The complaints were filed with the FERC under


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Section 206 of the FPA requesting that the FERC find the MISO regional base ROE rate (the “base ROE”) for all MISO TO’s, including our MISO Regulated Operating Subsidiaries, to no longer be just and reasonable.
Prior to the filing of the MISO ROE Complaints, complaints were filed with the FERC regarding the regional base ROE rate for ISO New England TOs. In resolving these complaints, the FERC adopted a methodology for establishing base ROE rates based on a two-step DCF analysis. This methodology provided the precedent for the FERC ruling on the Initial Complaint and the ALJ initial decision on the Second Complaint for our MISO Regulated Operating Subsidiaries discussed below.
Initial Complaint
On November 12, 2013, the Association of Businesses Advocating Tariff Equity, Coalition of MISO Transmission Customers, Illinois Industrial Energy Consumers, Indiana Industrial Energy Consumers, Inc., Minnesota Large Industrial Group and Wisconsin Industrial Energy Group (collectively, the “complainants”) filed the Initial Complaint with the FERC. The complainants sought a FERC order to reduce the base ROE used in the formula transmission rates for our MISO Regulated Operating Subsidiaries to 9.15%, reducing the equity component of our capital structure and terminating the ROE adders approved for certain Regulated Operating Subsidiaries. The FERC set the base ROE for hearing and settlement procedures, while denying all other aspects of the Initial Complaint.
On September 28, 2016, the FERC issued the September 2016 Order that set the base ROE at 10.32%, with a maximum ROE of 11.35%, effective for the period from November 12, 2013 through February 11, 2015 based on the two-step DCF methodology adopted in the ISO New England matters. The ROE collected through the MISO Regulated Operating Subsidiaries’ rates during the period November 12, 2013 through September 27, 2016, a portion of which was later refunded to customers for the period of the Initial Complaint, consisted of a base ROE of 12.38% plus applicable incentive adders.
The September 2016 Order required all MISO TOs, including our MISO Regulated Operating Subsidiaries, to provide refunds of $118 million, including interest, which were completed in 2017 as noted below in “Financial Statement Impacts”. Additionally, the base ROE established by the September 2016 Order was to be used prospectively from the date of that order until a new approved base ROE was established by the FERC. On October 28, 2016, the MISO TOs, including our MISO Regulated Operating Subsidiaries, filed a request with the FERC for rehearing of the September 2016 Order regarding the short-term growth projections in the two-step DCF analysis. Additional impacts to the base ROE for the period of the Initial Complaint and the related accrued refund liabilities resulted from the November 2019 Order issued by the FERC, as discussed below.
Second Complaint
On February 12, 2015, the Second Complaint was filed with the FERC by Arkansas Electric Cooperative Corporation, Mississippi Delta Energy Agency, Clarksdale Public Utilities Commission, Public Service Commission of Yazoo City and Hoosier Energy Rural Electric Cooperative, Inc., seeking a FERC order to reduce the base ROE used in the formula transmission rates of our MISO Regulated Operating Subsidiaries to 8.67%, with an effective date of February 12, 2015.
On June 30, 2016, the presiding ALJ issued an initial decision that recommended a base ROE of 9.70% for the refund period from February 12, 2015 through May 11, 2016, with a maximum ROE of 10.68%, which also would be applicable going forward from the date of a final FERC order.
Related FERC Orders
In April 2017, the D.C. Circuit Court vacated the precedent-setting FERC orders in the ISO New England matters that established and applied the two-step DCF methodology for the determination of base ROE. The court remanded the orders to the FERC for further justification of its establishment of the new base ROE for the ISO New England TOs. On October 16, 2018, in the New England matters, the FERC issued an order on remand which proposed a new methodology for 1) determining when an existing ROE is no longer just and reasonable; and 2) setting a new just and reasonable ROE if an existing ROE has been found not to be just and reasonable. The FERC established a paper hearing on how the proposed new methodology should apply to the ISO New England TOs ROE complaint proceedings. The FERC issued a similar order, the November 2018 Order, in the MISO ROE Complaints, establishing a paper hearing on the application of the proposed new methodology to the proceedings pending before the FERC involving the MISO TOs’ ROE, including our MISO Regulated Operating Subsidiaries.


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The November 2018 Order included preliminary illustrative calculations for the ROE that could have been established for the Initial Complaint, using the FERC's proposed methodology with financial data from the proceedings related to that complaint. The FERC’s preliminary calculations were not binding and could change, as significant changes to the methodology by the FERC were possible as a result of the paper hearing process. The November 2018 Order and our response to the order through briefs and reply briefs did not provide a reasonable basis for a change to the reserve or ROEs utilized for any of the complaint refund periods nor all subsequent periods.
November 2019 Order
On November 21, 2019, the FERC issued an order on the MISO ROE Complaints. The FERC did not adopt the methodology proposed in the November 2018 Order, which had proposed using four financial models to establish the base ROE. Instead, the FERC determined that two financial models should be used to determine the base ROE. The FERC applied that methodology to the Initial Complaint period and determined that the base ROE for the Initial Complaint should be 9.88% and the top of the range of reasonableness for that period should be 12.24%. The FERC determined that this base ROE should apply during the first refund period of November 12, 2013 to February 11, 2015 and from the date of the September 2016 Order prospectively. In the November 2019 Order, the FERC also dismissed the Second Complaint. Therefore, based on the November 2019 Order, for the Second Complaint refund period from February 12, 2015 to May 11, 2016, no refund is due, and the base ROE for that period should be 12.38% plus applicable incentive adders. As a result, we have reversed the aggregate estimated current liability we had previously recorded for the Second Complaint, as noted below in “Financial Statement Impacts”. In addition, from May 12, 2016 to September 27, 2016, the base ROE should be 12.38% plus applicable incentive adders, because no complaint had been filed for that period and no refund is due during that period. The FERC ordered refunds to be made in accordance with the November 2019 Order within 30 days, but on December 18, 2019 the FERC granted a request from MISO for an extension until December 23, 2020 for settlement of the refunds. The MISO TOs, including our MISO Regulated Operating Subsidiaries, and several other parties filed requests for rehearing of the November 2019 Order. The MISO TOs filed their request for rehearing primarily on the basis that the methodology applied by the FERC in the November 2019 Order will not allow the MISO TOs to earn a reasonable rate of return on their investment, as required by precedent. On January 21, 2020, the FERC issued an order granting rehearings for further consideration.
In January 2020, certain complainants in the MISO ROE dockets filed an appeal of the September 2016 Order and the November 2019 Order at the D.C. Circuit Court. We believe that the appeal was premature and should be dismissed, but if not, we will respond in due course.
Financial Statement Impacts
As of December 31, 2019, we had recorded a current regulatory liability in the consolidated statements of financial position of $70 million to reflect amounts due to customers under the terms outlined in the November 2019 Order on the Initial Complaint and the period from the date of the September 2016 Order to December 31, 2019. We had recorded an aggregate estimated current regulatory liability in the consolidated statements of financial position of $151 million as of December 31, 2018 for the Second Complaint, which was reversed in November 2019 following the November 2019 Order. Although the November 2019 Order dismissed the Second Complaint with no refunds required, it is possible upon rehearing that our MISO Regulated Operating Subsidiaries will be required to provide refunds related to the Second Complaint and these refunds could be material. It is also possible, upon rehearing of the November 2019 Order, that the outcome may differ materially from the November 2019 Order. In 2017, $118 million, including interest, was refunded to customers of our MISO Regulated Operating Subsidiaries for the Initial Complaint based on the refund liability associated with the September 2016 Order.
Our MISO Regulated Operating Subsidiaries currently record revenues at the base ROE of 9.88% established in the November 2019 Order plus applicable incentive adders. See Note 6 for a summary of incentive adders for transmission rates.


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The recognition of the obligations associated with the MISO ROE Complaints resulted in the following impacts to the consolidated statements of comprehensive income during each respective period:
 
Year Ended December 31,
(In millions)
2019
 
2018
 
2017
Revenue increase (decrease)
$
69

 
$
1

 
$
—

Interest expense increase (decrease)
(12
)
 
7

 
6

Estimated net income increase (reduction)
61

 
(4
)
 
(3
)

As of December 31, 2019, our MISO Regulated Operating Subsidiaries had a total of approximately $5 billion of equity in their collective capital structures for ratemaking purposes. Based on this level of aggregate equity, we estimate that each 10 basis point change in the authorized ROE would impact annual consolidated net income by approximately $5 million.
Development Projects
We are pursuing strategic development projects that may result in payments to developers that are contingent on the projects reaching certain milestones indicating that the projects are financially viable. We believe it is reasonably possible that we will be required to make these contingent development payments up to a maximum amount of $120 million for the period from 2020 through 2023. In the event it becomes probable that we will make these payments, we would recognize the liability and the corresponding intangible asset or expense as appropriate.
Purchase Obligations
At December 31, 2019, we had purchase obligations of $77 million representing commitments for materials, services and equipment that had not been received as of December 31, 2019, primarily for construction and maintenance projects for which we have an executed contract. Of these purchase obligations, $74 million is expected to be paid in 2020, with the majority of the items related to materials and equipment that have long production lead times.
Other Commitments
METC
Amended and Restated Purchase and Sale Agreement for Ancillary Services. Since METC does not own any generating facilities, it must procure ancillary services from third party suppliers, such as Consumers Energy. Currently, under the Ancillary Services Agreement, METC pays Consumers Energy for providing certain generation-based services necessary to support the reliable operation of the bulk power grid, such as voltage support and generation capability and capacity to balance loads and generation.
Amended and Restated Easement Agreement. Under the Easement Agreement, Consumers Energy provides METC with an easement to the land on which a majority of METC’s transmission towers, poles, lines and other transmission facilities used to transmit electricity for Consumers Energy and others are located. METC pays Consumers Energy $10 million in annual rent per year for the easement and also pays for any rentals, property, taxes, and other fees related to the property covered by the Easement Agreement. Payments to Consumers Energy under the Easement Agreement are charged to operation and maintenance expenses.
ITC Midwest
Operations Services Agreement For 34.5 kV Transmission Facilities. ITC Midwest and IP&L entered into the OSA under which IP&L performs certain operations functions for ITC Midwest’s 34.5 kV transmission system on behalf of ITC Midwest. The OSA provides that when ITC Midwest upgrades 34.5 kV facilities to higher operating voltages it may notify IP&L of the change and the OSA is no longer applicable to those facilities.
ITC Great Plains
Amended and Restated Maintenance Agreement. Mid-Kansas and ITC Great Plains have entered into the Mid-Kansas Agreement pursuant to which Mid-Kansas has agreed to perform various field operations and maintenance services related to certain ITC Great Plains assets.


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Concentration of Credit Risk
Our credit risk is primarily with DTE Electric, Consumers Energy and IP&L, which were responsible for approximately 21.1%, 23.2% and 24.8%, respectively, or $254 million, $279 million and $298 million, respectively, of our consolidated billed revenues for the year ended December 31, 2019. These percentages and amounts of total billed revenues of DTE Electric, Consumers Energy and IP&L include the collection of 2017 revenue accruals and deferrals and exclude any amounts for the 2019 revenue accruals and deferrals that were included in our 2019 operating revenues but will not be billed to our customers until 2021. Under DTE Electric’s and Consumers Energy’s current rate structure, DTE Electric and Consumers Energy include in their retail rates the actual cost of transmission services provided by ITCTransmission and METC, respectively, in their billings to their customers, effectively passing through to end-use consumers the total cost of transmission service. IP&L currently includes in their retail rates an allowance for transmission services provided by ITC Midwest in their billings to their customers. However, any financial difficulties experienced by DTE Electric, Consumers Energy or IP&L may affect their ability to make payments for transmission service to ITCTransmission, METC, and ITC Midwest, which could negatively impact our business. MISO, as our MISO Regulated Operating Subsidiaries’ billing agent, bills DTE Electric, Consumers Energy, IP&L and other customers on a monthly basis and collects fees for the use of the MISO Regulated Operating Subsidiaries’ transmission systems. SPP is the billing agent for ITC Great Plains and bills transmission customers for the use of ITC Great Plains transmission systems. MISO and SPP have implemented strict credit policies for its members’ customers, which include customers using our transmission systems. Specifically, MISO and SPP require a letter of credit or cash deposit equal to the credit exposure, which is determined by a credit scoring model and other factors, from any customer using a member’s transmission system.
The financial results of ITC Interconnection are currently not material to our consolidated financial statements, including billed revenues.
20.    SUPPLEMENTAL FINANCIAL INFORMATION
Reconciliation of Cash, Cash Equivalents and Restricted Cash
The following table provides a reconciliation of cash, cash equivalents and restricted cash reported on the consolidated statements of financial position that sum to the total of the same such amounts shown in the consolidated statements of cash flows:
 
December 31,
(In millions)
2019
 
2018
 
2017
 
2016
Cash and cash equivalents
$
4

 
$
6

 
$
66

 
$
8

Restricted cash included in:
 
 
 
 
 
 
 
Other non-current assets
2

 
4

 
2

 
3

Total cash, cash equivalents and restricted cash
$
6

 
$
10

 
$
68

 
$
11


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


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Supplementary Cash Flow Information
 
Year Ended December 31,
(In millions)
2019
 
2018
 
2017
Supplementary cash flows information:
 
 
 
 
 
Interest paid (net of interest capitalized) (a)
$
228

 
$
223

 
$
213

Income tax refunds received
3

 
13

 
1

Supplementary non-cash investing and financing activities:
 
 
 
 
 
Additions to property, plant and equipment and other long-lived assets (b)
92

 
94

 
87

Allowance for equity funds used during construction
29

 
33

 
33

Right-of-use assets obtained in exchange for new operating lease liabilities (c)
5

 
—

 
—

____________________________
(a)
Amount for the year ended December 31, 2017 includes $9 million of interest paid associated with the Initial Complaint. See Note 19 for information on the Initial Complaint.
(b)
Amounts consist of current and accrued liabilities for construction, labor, materials and other costs that have not been included in investing activities. These amounts have not been paid for as of December 31, 2019, 2018 or 2017, respectively, but will be or have been included as a cash outflow from investing activities for expenditures for property, plant and equipment when paid.
(c)
See Note 2 for information regarding the adoption of lease guidance in 2019.
Excess tax benefits are recognized as an adjustment to income tax expense in the consolidated statements of comprehensive income. Cash retained as a result of those excess tax benefits is presented in the consolidated statements of cash flows as cash inflows from operating activities.
21.    SEGMENT INFORMATION
We identify reportable segments based on the criteria set forth by the FASB regarding disclosures about segments of an enterprise, including the regulatory environment of our subsidiaries and the business activities performed to earn revenues and incur expenses.
Regulated Operating Subsidiaries
We aggregate ITCTransmission, METC, ITC Midwest, ITC Great Plains and ITC Interconnection into one reportable operating segment based on their similar regulatory environment and economic characteristics, among other factors. They are engaged in the transmission of electricity within the United States, earn revenues from the same types of customers and are regulated by the FERC.
ITC Holdings and Other
Information below for ITC Holdings and Other consists of a holding company whose activities include debt financings and general corporate activities and all of ITC Holdings’ other subsidiaries, excluding the Regulated Operating Subsidiaries, which are focused primarily on business development activities.


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Regulated
 
 
 
 
 
 
 
Operating
 
ITC Holdings
 
Reconciliations/
 
 
2019
Subsidiaries
 
and Other
 
Eliminations
 
Total
(In millions)
 
 
 
 
 
 
 
Operating revenues
$
1,358

 
$
—

 
$
(31
)
 
$
1,327

Depreciation and amortization
201

 
2

 
—

 
203

Interest expense, net
105

 
119

 
—

 
224

Income (loss) before income taxes
710

 
(150
)
 
—

 
560

Income tax provision (benefit)
179

 
(47
)
 
—

 
132

Net income
531

 
428

 
(531
)
 
428

Property, plant and equipment, net
8,573

 
9

 
—

 
8,582

Goodwill
950

 
—

 
—

 
950

Total assets (a)
9,946

 
5,402

 
(5,290
)
 
10,058

Capital expenditures
874

 
—

 
(9
)
 
865

 
Regulated
 
 
 
 
 
 
 
Operating
 
ITC Holdings
 
Reconciliations/
 
 
2018
Subsidiaries
 
and Other
 
Eliminations
 
Total
(In millions)
 
 
 
 
 
 
 
Operating revenues
$
1,185

 
$
—

 
$
(29
)
 
$
1,156

Depreciation and amortization
179

 
1

 
—

 
180

Interest expense, net
110

 
114

 
—

 
224

Income (loss) before income taxes
585

 
(144
)
 
—

 
441

Income tax provision (benefit)
148

 
(37
)
 
—

 
111

Net income
437

 
330

 
(437
)
 
330

Property, plant and equipment, net
7,901

 
9

 
—

 
7,910

Goodwill
950

 
—

 
—

 
950

Total assets (a)
9,224

 
4,977

 
(4,872
)
 
9,329

Capital expenditures
773

 
—

 
(4
)
 
769

 
Regulated
 
 
 
 
 
 
 
Operating
 
ITC Holdings
 
Reconciliations/
 
 
2017
Subsidiaries
 
and Other
 
Eliminations
 
Total
(In millions)
 
 
 
 
 
 
 
Operating revenues
$
1,241

 
$
—

 
$
(30
)
 
$
1,211

Depreciation and amortization
168

 
1

 
—

 
169

Interest expense, net
104

 
120

 
—

 
224

Income (loss) before income taxes
664

 
(149
)
 
—

 
515

Income tax provision (benefit)
207

 
(11
)
 
—

 
196

Net income
457

 
319

 
(457
)
 
319

Property, plant and equipment, net
7,299

 
10

 
—

 
7,309

Goodwill
950

 
—

 
—

 
950

Total assets (a)
8,688

 
4,799

 
(4,664
)
 
8,823

Capital expenditures
761

 
—

 
(6
)
 
755

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


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22.    SUPPLEMENTARY QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
 
First
 
Second
 
Third
 
Fourth
 
 
(In millions)
Quarter
 
Quarter
 
Quarter
 
Quarter
 
Year
2019
 
 
 
 
 
 
 
 
 
Operating revenues
$
307

 
$
320

 
$
321

 
$
379

(a)
$
1,327

Operating income
166

 
171

 
174

 
244

(a)
755

Net income
84

 
87

 
98

 
159

(a)
428

2018
 
 
 
 
 
 
 
 
 
Operating revenues
$
279

 
$
290

 
$
295

 
$
292

 
$
1,156

Operating income
154

 
163

 
163

 
155

 
635

Net income
82

 
79

 
89

 
80

 
330


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


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ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
ITEM 9A.     CONTROLS AND PROCEDURES.
Management’s Report on Internal Control Over Financial Reporting is included in Item 8 of this Form 10-K.
Disclosure Controls and Procedures
We maintain disclosure controls and procedures that are designed to provide reasonable assurance that material information required to be disclosed in our reports that we file or submit under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required financial disclosure. In designing and evaluating the disclosure controls and procedures, management recognized that a control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, with a company have been detected.
As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 of the Exchange Act. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective, at the reasonable assurance level.
Changes in Internal Control over Financial Reporting
There have been no changes in our internal control over financial reporting during the quarter ended December 31, 2019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B.     OTHER INFORMATION.
None.
PART III
ITEM 10.     DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.
DIRECTORS
Our Bylaws provide for the election of directors at each annual meeting of shareholders. Each director serves until the next annual meeting and until his or her successor is elected and qualified, or until his or her resignation or removal.
Pursuant to the Merger Agreement and the Shareholders Agreement, the Board must consist of the Chief Executive Officer of the Company (Ms. Apsey), a representative of Eiffel, the GIC subsidiary that is a minority investor in ITC Investment Holdings (Mr. Greenbaum), a minority of representatives of Fortis (Messrs. Perry and Laurito) and a majority of directors who are independent of Fortis. All directors must be independent of any “market participant” in MISO and SPP and a majority of the directors must be “independent” as defined in the Shareholders Agreement. See “Item 13 Certain Relationships And Related Transactions, And Director Independence — Director Independence.”
Linda H. Apsey, 50. Ms. Apsey became President and Chief Executive Officer of the Company in November 2016 and was elected a director of the Company in January 2017. From May 2016 through January 2017, Ms. Apsey served as the Company’s Executive Vice President and Chief Business Unit Officer, where she was responsible for leading all aspects of the financial and operational performance of our five Regulated Operating Subsidiaries and the Company’s development. She had previously served as the Company’s Executive Vice President, Chief Business Unit Officer and President, ITC Michigan since February 2015 where she was responsible for leading all aspects of the financial and operational performance of the Company’s five Regulated Operating


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Subsidiaries and acting as the business unit head and president of the ITCTransmission and METC operating companies. Ms. Apsey currently serves as a director of the Fortis utility subsidiary, FortisAlberta Inc.
Robert A. Elliott, 64. Mr. Elliott became a director of the Company in January 2017. Mr. Elliott has served as President and Owner of Elliott Accounting, an accounting, income tax and management advisory services organization in Tucson, Arizona, since 1983. He also serves as an Investment Advisor Representative for Greenberg Financial Group, a brokerage firm, a position in which he has served since 2001. Mr. Elliott is currently the Chairman of the Board of UNS Energy Corporation, a subsidiary of Fortis, and has been a board member of that company since 2014. Mr. Elliott currently serves on the board of directors of AAA CSAA Insurance and AAA Auto Club Partners and is the Chair of the board of directors of AAA Mountain West Group and has been a board member of that company since 2016. He previously served on the board of directors of AAA Arizona Inc. from 2007 to 2016. The Board selected Mr. Elliott to serve as a director because of his accounting experience, his familiarity with Fortis subsidiary operations and his experience serving as a leader on other boards of directors.
Albert Ernst, 70. Mr. Ernst became a director of the Company in January 2017. Mr. Ernst was also a member of the ITC Holdings Board of Directors from August 2014 through the closing of the transactions resulting from the Merger Agreement in October 2016, as described in the Merger Agreement. Mr. Ernst is a retired member of the law firm of Dykema Gossett PLLC, where he also served as director of Dykema’s Energy Industry Group. His experience with companies in the public utility, energy, transmission, telecommunications and rural electric cooperative fields spans more than three decades. With Dykema, Mr. Ernst worked with leading energy clients including our subsidiaries, ITCTransmission and METC. He also served as a consultant on utility-related matters to the U.S. Department of Defense, the DOE and the General Services Administration. The Board selected Mr. Ernst to serve as a director due to his lifelong career in the energy industry, as well as his invaluable experience with public utility and energy matters and decades of experience in the practice of law.
Alexander I. Greenbaum, 36. Mr. Greenbaum became a director of the Company in July 2019. Mr. Greenbaum is the Senior Vice President of Infrastructure for GIC. In this role he is responsible for acquisitions and asset management for a portfolio of power, utility, midstream and transportation assets. Prior to rejoining GIC in May 2015, he was an Executive Director in the Infrastructure group of UBS Investment Bank from July 2005 until May 2015. Mr. Greenbaum currently serves on the board of directors of Arrowhead ST Holdings, a crude oil pipeline operator, HEP Catalyst InvestCo, a crude oil and natural gas gathering and processing company in the Permian Basin, and Genesee & Wyoming Railroad. He previously served on the boards of directors of Starwest Generation, an independent power producer with operations in Arizona, and Texas Transmission Holdings Company. Mr. Greenbaum was appointed as a member of our Board of Directors by Eiffel.
James P. Laurito, 63. Mr. Laurito became a director of the Company in October 2016. Mr. Laurito has served as Fortis’ Executive Vice President, Business Development since April 2016. Previously, Mr. Laurito served as the President and Chief Executive Officer of Fortis’ Central Hudson Gas & Electric Corporation subsidiary from January 2010 to November 2014. Prior to joining Central Hudson, Mr. Laurito served as the President and Chief Executive Officer of both New York State Electric and Gas Corporation and Rochester Gas and Electric Corporation, subsidiaries of Avangrid, Inc. Mr. Laurito has been Chairman of the Hudson Valley Economic Development Corporation since January 1, 2015 and currently serves on the board of Fortis’ Central Hudson Gas & Electric Corporation subsidiary.
Barry V. Perry, 55. Mr. Perry became a director of the Company in October 2016. Mr. Perry is President and Chief Executive Officer of Fortis and has served as such since January 2015. Prior to his current position at Fortis, Mr. Perry served as President from June 30, 2014 to December 31, 2014 and prior to that served as Vice President, Finance and Chief Financial Officer since 2004. Mr. Perry joined the Fortis organization in 2000 as Vice President, Finance and Chief Financial Officer of Newfoundland Power Inc. Mr. Perry currently serves as a director of the Fortis utility subsidiaries, FortisBC and UNS Energy Corporation.
Sandra E. Pierce, 61. Ms. Pierce became a director of the Company in January 2017. Ms. Pierce is Senior Executive Vice President, Private Client Group & Regional Banking Director and Chair of Michigan for Huntington National Bank. Ms. Pierce joined Huntington in 2016 after its merger with FirstMerit Corporation in 2016. While at FirstMerit, Ms. Pierce served as Vice Chairman of FirstMerit Corporation and Chairman and CEO of FirstMerit Michigan, from 2013 to 2016. Ms. Pierce currently serves as a board member of Barton Malow Enterprises, Penske Automotive Group and American Axle & Manufacturing, Inc. She also serves as the current chair of the Detroit Financial Advisory Board and the chair of the Henry Ford Health System. The Board selected Ms. Pierce to serve


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as a director due to her leadership experience and familiarity with the geographic region in which the Company operates and conducts business.
Kevin L. Prust, 64. Mr. Prust became a director of the Company in January 2017. Mr. Prust retired in 2014 as Executive Vice President and Chief Financial Officer of The Weitz Company, LLC, a large national and international construction firm, a position he held since joining the company in 2009. Prior to that, Mr. Prust was with McGladrey & Pullen LLP, a national CPA firm, from 1978 through 2008 serving in various positions and becoming partner in 1985. Mr. Prust previously served on the board of Mercy Medical Center, in Des Moines, Iowa from 2009 to 2018. In 2015 Mr. Prust served on the board of Stock Building Supply Holdings, Inc. until the company was acquired. The Board selected Mr. Prust to serve as a director because of the expansive financial and accounting experience he obtained as a chief financial officer as well as his familiarity with the geographic region in which the Company operates and conducts business. The Board has determined that Mr. Prust is an “audit committee financial expert”, as that term is defined under SEC rules.
A. Douglas Rothwell, 63. Mr. Rothwell became a director of the Company in October 2017. Since 2005 Mr. Rothwell has served as President and CEO of Business Leaders for Michigan - a business roundtable of the state’s top 100 CEOs. Mr. Rothwell currently Co-chairs Launch Michigan, the state’s education improvement coalition, and the University of North Carolina at Chapel Hill’s (“UNC”) Ackland Museum board in addition to serving as an Executive Residence for Economic Development at UNC. He previously chaired the Michigan Economic Development Corporation, the American Center for Mobility and the UNC Board of Visitors. The Board selected Mr. Rothwell to serve as a director because of his vast experience working with business leaders in various industries to foster business development and growth and his familiarity and business contacts within the geographic region in which the Company operates and conducts business.
Thomas G. Stephens, 71. Mr. Stephens became a director of the Company in January 2017. Mr. Stephens was also a member of the Board of Directors from November 2012 through the closing of transactions resulting from the Merger Agreement in October 2016, as described in the Merger Agreement. Mr. Stephens retired in April 2012 from General Motors Company, a designer, manufacturer and marketer of vehicles and automobile parts, after 43 years with the company. Prior to his retirement, Mr. Stephens served as Vice Chairman and Chief Technology Officer. Mr. Stephens currently is Vice Chairman of the board of FIRST (For Inspiration and Recognition of Science and Technology in Michigan Robotics), Chairman of the Board of the Michigan Science Center and sits on the Board of Managers of Warehouse Technologies LLC and the board of directors of xF Technologies Inc. The Board selected Mr. Stephens to serve as a director because of his strong technical and engineering background as well as his experience and proven leadership capabilities assisting a large organization to achieve its business objectives.
Joseph L. Welch, 71. Mr. Welch has served as Chairman of the Board of Directors of the Company since May 2008 and as a director since 2003. He served as the Company’s President and Chief Executive Officer from 2003 until November 2016 and also served as the Company’s Treasurer from 2003 until 2009. As the founder of ITCTransmission, Mr. Welch has had overall responsibility for the Company’s vision, foundation and transformation into the first independently owned and operated electricity transmission company in the United States. Mr. Welch worked for Detroit Edison Company and other subsidiaries of DTE Energy from 1971 to 2003. During that time, he held positions of increasing responsibility in the electricity transmission, distribution, rates, load research, marketing and pricing areas, as well as regulatory affairs that included the development and implementation of regulatory strategies. Mr. Welch currently serves as a director of Fortis. The Board selected Mr. Welch to serve as a director because he previously served as the Company’s President and Chief Executive Officer and he possesses unparalleled expertise in the electric transmission business.
EXECUTIVE OFFICERS
Set forth below are the names, ages and titles of our current executive officers and a description of their business experience. Our executive officers serve as executive officers at the pleasure of the Board of Directors.
Linda H. Apsey, 50. Ms. Apsey’s background is described above under “Directors.”
Gretchen L. Holloway, 45. Ms. Holloway was named Senior Vice President and Chief Financial Officer in July 2017. Prior to this role, Ms. Holloway served as Vice President, Interim Chief Financial Officer and Treasurer, a position in which she served since October 2016. In her role, Ms. Holloway is responsible for the Company’s accounting, internal audit, treasury, financial planning and analysis, management reporting, risk management and tax functions. From May 2016 to October 2016, Ms. Holloway was Vice President and Treasurer and from November


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2015 until May 2016, Ms. Holloway served as Vice President, Finance and Treasurer of the Company. In this role and her immediate past role, she was responsible for all treasury and corporate planning activities including cash management and as the Company’s liaison with the investment banking community and rating agencies. Ms. Holloway served from February 2015 to November 2015 as Vice President, Finance of the Company, where she was responsible for corporate finance activities including oversight of the budget and forecast processes and other financial analysis. Prior to that, Ms. Holloway served from June 2010 until February 2015 as Director, Special Projects & Investor Relations of the Company, where she was responsible for supporting the sourcing, evaluation and execution of mergers and acquisitions and implementing investor relations strategies and objectives. Ms. Holloway currently serves as a member of the Finance & Audit Committee for the Children’s Hospital of Michigan Foundation and as a member of the Board of Directors of Inforum.
Jon E. Jipping, 53. Jon E. Jipping has served as Executive Vice President and Chief Operating Officer since June 2007. Mr. Jipping is responsible for transmission system planning, system operations, engineering, supply chain, field construction and maintenance, and information technology. Prior to this appointment, Mr. Jipping served as Senior Vice President - Engineering and was responsible for transmission system design, project engineering and asset management. Mr. Jipping joined the Company as Director of Engineering in March 2003, was appointed Vice President - Engineering in 2005 and was named Senior Vice President in February 2006. Mr. Jipping currently serves on the board of Wataynikaneyap Power PM Inc., an entity owned by FortisOntario, Inc., a subsidiary of Fortis, which was created to develop and operate transmission to connect remote First Nation communities to the electrical grid in northwestern Ontario, Canada. He also serves as the Chair of the Advisory Board of the Michigan Technological University College of Engineering and as the Chair of the Board of the North American Transmission Forum.
Daniel J. Oginsky, 46. Mr. Oginsky has served as Executive Vice President and Chief Administrative Officer since May 2016. In this role, he has responsibility for the Company’s regulatory, federal affairs, marketing and communications, human resources, strategic planning and enterprise planning process and state government affairs. Mr. Oginsky served as Executive Vice President, U.S. Regulated Grid Development from February 2015 to May 2016. He was responsible for leading the Company’s growth and expansion through new investments in regulated electric transmission infrastructure across the United States. Mr. Oginsky joined as our Vice President and General Counsel in November 2004, served as Senior Vice President and General Counsel since May 2009 and was named Executive Vice President and General Counsel in May 2014. In these roles, Mr. Oginsky was responsible for the legal affairs of the Company and oversaw the legal department, which included the legal, corporate secretary, real estate, contract administration and corporate compliance functions. Mr. Oginsky served as a member of the Advisory Board of Belle Tire, Inc. from 2012 to 2019. Mr. Oginsky currently serves as President of North Manitou Light Keepers, Inc. and as a member of the Board of Visitors for James Madison College at Michigan State University.
Christine Mason Soneral, 47. Christine Mason Soneral was named Senior Vice President and General Counsel in April 2015 and served as Vice President and General Counsel from February 2015 through this appointment. As General Counsel, she is responsible for all corporate legal affairs and the leadership of our legal department. Prior to this role, Ms. Mason Soneral was Vice President and General Counsel-Utility Operations since 2007 and was responsible for legal matters connected with the operations, capital projects, contract, regulatory, property and litigation matters of the Company’s Regulated Operating Subsidiaries. In 2014, Ms. Mason Soneral was appointed to the board of Citizens Research Council, a privately funded, not-for-profit public affairs research organization. Ms. Mason Soneral also currently serves as a member of the Michigan State University College of Social Science's External Advisory Board and Women’s Leadership Institute.
Krista Tanner, 45. Ms. Tanner has served as our Senior Vice President and Chief Business Unit Officer since February 2019. Ms. Tanner is responsible for strategic direction, customer service, local government and community affairs and financial performance for four of the Company’s operating subsidiaries: ITC Midwest, ITC Great Plains, ITCTransmission and METC. Ms. Tanner joined the Company in November 2014 where she served as Vice President, ITC Holdings and President, ITC Midwest. In this role she served as the business unit head, providing leadership and strategic direction for ITC Midwest. Ms. Tanner joined the Company from Alliant Energy, where she served as director of regulatory policy from 2011 to 2014. While at Alliant Energy she directed Alliant Energy’s regional and federal regulatory policy group and led Alliant Energy’s legal strategy across regulatory jurisdictions. Ms. Tanner previously served as a member of the Board of Directors of the Midwest Reliability Organization from 2017 to 2019. Ms. Tanner currently serves as a member of the Board of Directors of Delta Dental of Iowa.


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Code of Conduct and Ethics
We have adopted a Code of Conduct and Ethics that applies to all of our directors, employees and executive officers, including our chief executive officer, chief financial officer and principal accounting officer. The Code of Conduct and Ethics, as currently in effect (together with any amendments that may be adopted from time to time), is available on our website at www.itc-holdings.com. To the extent required by the Code of Conduct and Ethics or by applicable law, we will post any amendments to the Code of Conduct and Ethics and any waivers that are required to be disclosed by the rules of the SEC on our website, within the required periods.
ITEM 11.     EXECUTIVE COMPENSATION.
COMPENSATION OF EXECUTIVE OFFICERS AND DIRECTORS
Compensation Discussion and Analysis
The following Compensation Discussion and Analysis describes the elements of compensation for our Chief Executive Officer (or “CEO”), our Chief Financial Officer and the three other most highly compensated executive officers who were serving as such at December 31, 2019. We refer to these individuals collectively as the “named executive officers” or “NEOs”.
The Company’s named executive officers for 2019 were:
Name
Position
Linda H. Apsey
President and Chief Executive Officer
Gretchen L. Holloway
Senior Vice President and Chief Financial Officer
Jon E. Jipping
Executive Vice President and Chief Operating Officer
Daniel J. Oginsky
Executive Vice President and Chief Administrative Officer
Christine Mason Soneral
Senior Vice President and General Counsel
Executive Summary
The Governance and Human Resources Committee (the “Committee”) is responsible for determining the compensation of our NEOs and administering the plans in which the NEOs participate. The goals of our compensation system are to attract first-class executive talent in a competitive environment and to motivate and retain key employees who are crucial to our success by rewarding Company and individual performance that promotes long-term sustainable growth and increases shareholder value. The key components of our NEOs' compensation package include base salary, annual cash incentive bonuses, long-term equity incentives, as well as certain perquisites and other benefits. In determining the amount of NEO compensation, we consider competitive compensation practices of other utilities and similarly sized organizations, the executive's individual performance against objectives, the executive's responsibilities and expertise, and our performance in relation to annual goals that are designed to strengthen and enhance our value.
The Committee made the following decisions with regard to executive compensation in 2019:
•
Base salary increases. Base salary increases were provided to each of our NEOs in 2019 to reward individual performance and to remain competitive and aligned with market.
•
Annual cash incentive bonuses. The NEOs earned cash incentive bonuses for 2019 performance of approximately 169% of target. This was based on achieving 100% of the performance targets established under the annual corporate performance bonus plan in early 2019 and achievement of certain performance factors which resulted in a bonus multiplier of 1.69. See “Compensation Discussion and Analysis - Key Components of Our NEO Compensation Program - Annual Corporate Performance Bonus.”
•
Long-term equity incentives. We granted long-term equity incentive awards to our NEOs in March 2019. Total award opportunities were set as a percentage of base salary and delivered one-third in the form of SBUs and two-thirds in the form of PBUs.


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Overview and Philosophy
The objectives of our compensation program are to attract first-class executive talent in a competitive environment and to motivate and retain key employees who are crucial to our success by rewarding Company and individual performance that promotes long-term sustainable growth and increases shareholder value by:
•
Performing best-in-class utility operations;
•
Improving reliability, reducing congestion, and facilitating access to generation resources; and
•
Utilizing our experience and skills to seek and identify opportunities to invest in needed transmission and to optimize the value of those investments.
Our compensation program is designed to motivate and reward individual and corporate performance. Our compensation philosophy is to:
•
Provide for flexibility in pay practices to recognize our unique position and growth proposition;
•
Use a market-based pay program aligned with pay-for-performance objectives;
•
Leverage incentives, where possible, and align long-term incentive awards with improvements in our financial performance and shareholder value;
•
Provide benefits through flexible, cost-effective plans while taking into account business needs and affordability; and
•
Provide other non-monetary awards to recognize and incentivize performance.
Risk and Reward Balance
When reviewing the compensation program, the Committee considers the impact of the program on the Company’s risk profile. The Committee believes that the compensation program has been structured with the appropriate mix and design of elements to provide strong incentives for executives to balance risk and reward, without excessive risk taking.
The Committee engaged FW Cook, its independent compensation consultant, to conduct an annual comprehensive compensation program risk assessment. In July 2019, FW Cook reviewed the attributes and structure of our executive compensation programs for the purpose of identifying potential sources of risk within the program design. The review covered compensation plan design and administration/governance risk.
Based on a report from FW Cook concluding that the Company’s compensation programs do not create risks that are reasonably likely to have a material adverse impact on the Company, the Committee concluded that none of our compensation programs and features contain elements that create material risk to the Company. Risk mitigating factors with respect to the Company’s compensation programs included a market competitive pay mix, the linking of pay to performance through annual cash bonus and long-term equity incentive plans, caps on annual cash bonus and long-term equity incentive plan payouts, various performance measures that are both financially and operationally focused, a compensation recoupment policy, oversight by an independent committee of directors, regular review of NEO tally sheets and engagement of an independent compensation consultant.
Benchmarking and Relationship of Compensation Elements
Benchmarking. We reviewed market competitive target pay levels from two distinct market samples, utility and general industry data, as reflected in published surveys. FW Cook, the Committee’s independent advisor, compiled data for the following components of compensation — base salary, target annual cash bonus incentive and target long-term equity incentive, as well as target total cash compensation and target total direct compensation. Position-specific market target pay levels are reviewed for utility-specific data from the Willis Towers Watson Energy Services Executive Compensation Survey and general industry data from the Willis Towers Watson General Industry Executive Compensation Survey. For staff jobs, competitive rates were developed for each of the two distinct market reference points, as well as an average of the two market reference points. For utility operations jobs, we only used the utility-specific data due to the industry-specific nature of the roles. The market data were aged and size-adjusted to correspond to our adjusted revenue scope. The adjusted revenue scope accounts for our unique business model and reflects the competitive incremental revenue that would normally be embedded in rates to reflect a typical cost of goods sold factor.
Our compensation strategy has been to target compensation to be in the range between the median and 75th percentile of the market data, based on consideration of individual characteristics (performance, experience, etc.), internal equity and other factors. In February 2019, the Committee reviewed the benchmarking study conducted by


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its independent consultant comparing NEO target total direct compensation, which is the sum of base salary, target annual incentives and target long-term incentives, to the 50th, 65th and 75th percentile survey data to assess the market competitiveness of our compensation opportunities. Overall, the study found target total direct compensation provided to our NEOs is within the targeted range.
Use of Tally Sheets. The Committee reviews tally sheets, every other year, as prepared by management to facilitate its assessment of the total annual compensation of our NEOs. The tally sheets contain annual cash compensation (salary and bonuses), long-term equity incentives, benefit contributions and perquisites. In addition, the tally sheets include retirement program balances, outstanding vested and unvested equity values and potential severance and termination scenario values.
Pay Review Process. In addition to the Committee’s benchmarking analysis, our CEO reviewed and examined market survey compensation levels and practices, as well as individual responsibilities and performance, our compensation philosophy and other related information to develop proposed compensation for each of our NEOs, other than herself. Ms. Apsey evaluated the performance of the NEOs, other than herself, and made recommendations on their salaries, target cash bonus incentive levels and long-term equity incentive awards. The Committee considered these recommendations in its decision making and conferred with Pay Governance, its compensation consultant at the time, to understand the impact and result of any such recommendations. The Committee uses market data and recommendations from the Committee’s consultant and makes recommendations on Ms. Apsey’s salary, cash bonus incentive targets and long-term equity incentive awards to the Board of Directors. The Board of Directors (other than Ms. Apsey) evaluates Ms. Apsey’s performance and considers the Committee’s recommendations in its decision making.
The Committee reviewed and considered each element of compensation and the resulting target total direct compensation, along with the objectives of our compensation program, the input of the CEO and the market data to set the 2019 target pay levels. The Committee did not determine the mix of compensation elements using a pre-set formula. In setting executive compensation levels, the Committee retained full discretion to consider or disregard data collected through benchmarking studies. Compensation decisions also considered individual and Company performance, retention concerns, the importance of the position, internal equity and other factors.
Key Components of Our NEO Compensation Program
The key components of our executive compensation program are discussed below.
•
Base Salary — provides sufficient competitive pay to attract and retain experienced and successful executives.
•
Cash Bonus Incentive — encourages and rewards contributions to our annual corporate performance goals.
•
Long Term Equity Incentives — encourages a multi-year focus on performance, rewards building long-term shareholder value and helps retain NEOs.
The other elements of our executive compensation program are discussed below under the heading “Other Components of Our Executive Compensation Program” which summarize the benefit programs that are available to our NEOs.
In aggregate, the NEOs’ target total direct compensation value (salary, annual target bonus and long-term incentive opportunities) was generally within the targeted range when compared to the blended average of the utility and general industry surveys. Base salaries are generally at the lower end of the targeted market range with target incentive opportunities set higher within the market range, which combine to provide competitive target total direct compensation around the target range of the market 50th and the 75th percentile. The Committee continues to monitor and balance competitive practice, talent needs and cost considerations when setting compensation.
Base Salary
The Committee annually reviews and approves the base salaries, and any adjustments thereto, of the NEOs. In making these determinations, the Committee considers the executive’s job responsibilities, individual performance, leadership and years of experience, the performance of the Company, the recommendation of the CEO (except for the base salary of the CEO) and the target total direct compensation package as well as the benchmarking analysis conducted by its advisor.


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The 2019 base salaries for the NEOs, including any year-over-year change, were:
NEO
 
2018 Base Salary
 
2019 Base Salary
 
Percent Increase
Linda H. Apsey
 
$
755,000

 
$
800,000

 
6.0
%
Gretchen L. Holloway
 
370,000

 
390,000

 
5.4
%
Jon E. Jipping
 
555,000

 
580,000

 
4.5
%
Daniel J. Oginsky
 
468,000

 
485,000

 
3.6
%
Christine Mason Soneral
 
378,000

 
390,000

 
3.2
%
Annual Corporate Performance Bonus
Early each year, the Committee approves our annual corporate performance bonus plan goals and targets, which are based on key Company objectives relating to operational excellence and superior financial performance. The corporate performance goals and targets were designed to align the interests of customers, the shareholder and management, and encourage teamwork and coordination among all of our executives and employees with a common focus on the growth and success of the Company. Target levels for the corporate performance goals were determined based on long-term strategic plans, historical performance, expectations for future growth and desired improvement over time.
The annual corporate performance bonus plan goals were individually weighted. Weights were assigned to each goal based on areas of focus during the year and difficulty in achieving target performance. Weights were also assigned so that there was a balance between operational and financial goals. Each goal operated independently, and, for most goals, there was not a range of acceptable performance; if a goal was not achieved, there was no payout for that goal. The plan would not pay for achieving below-target performance on any goal but would pay for achievement of target performance on those goals that were achieved even though other goals were not achieved. Where performance goals were stated in a range, the threshold goals were generally expected to be achieved while the maximum goals were considered “stretch” goals with lower expectation of achievement. The bonus goal targets were established to motivate NEOs toward operational excellence and superior financial performance and were designed to be challenging to meet, while remaining achievable.
For 2019, financial measures, representing 20%, plus the capital project plan, representing 30%, determined 50% of the target bonus opportunity, while operational performance measures, including Safety & Compliance, representing 20% and System Performance, representing 30%, determined the remaining 50% of the target bonus opportunity. This reflected the inherent importance of driving operational performance, reliability and needed investment in our transmission system for the benefit of our customers.
The annual corporate performance bonus plan consisted of three primary measurement categories: Financial, Safety & Compliance, and System Performance. Our safety, operations and security goals were established to deliver high performance in core company operations. Benchmarks and metrics were used in connection with these goals to establish a level of performance in the top decile or quartile within our industry. Likewise, our infrastructure protection goals led to the deployment of industry leading practices resulting in a generally enhanced security posture.
Corporate performance goal criteria approved by the Committee for 2019, the rationale for the target goal (in some cases in relation to the prior year target) and actual bonus results, were as set forth below.


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Financial goals represented 20% of the total maximum annual bonus target and included specific measures for Non-Field Operation and Maintenance Expense and Net Income.
Category
 
Goal
 
Rationale for Goal
 
Rationale for Target Goal
 
Potential Payout
 
2019 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 2018 and based on the 2019 Board-approved budget.

Non-Field O&M and G&A expense at or under budget of $164M.
 
10
%
 
$160M
 
10%
 
Adjusted Net Income (1)
 
Represents the Company’s financial performance as it reflects a true measure of earnings contributions from the operating companies.
 
Target based on the 2019 Board-approved budget.

Net Income from our Regulated Operating Subsidiaries at or above $468M to achieve 10%;
Net Income at or above $445M to achieve 5%.
 
5% - 10%

 
$484M
 
10%
Total
 
20
%
 
 
 
20%


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Safety & Compliance goals represented 20% of the total maximum annual bonus target and included specific measures for Lost Time, Recordable Incidents and Infrastructure Protection.
Category
 
Goal
 
Rationale for Goal
 
Rationale for Target
 
Potential Payout
 
2019 Results
 
Actual Payout
Safety & Compliance

20% Maximum Potential Payout
 
Safety as measured by lost time
 
Maintaining the safety of our employees and contractors is a core value and is at the foundation of our success.
 
Target number of incidents remained the same as prior years and was based on industry top decile performance, which reflects an aggressive view and philosophy on the importance of safety.

2 or fewer lost work day cases for injuries to Company employees and specified contract employees.
 
5
%
 
1
 
5%
 
Safety as measured by recordable incidents
 
Maintaining the safety of our employees and contractors is a core value and is at the foundation of our success.
 
Target number of incidents remained the same as prior year and was based on industry top decile performance, which reflects an aggressive view and philosophy on the importance of safety.

9 or fewer recordable incidents for injuries to Company employees and specified contract employees.
 
5
%
 
4
 
5%
 
Infrastructure Protection
 
Maintaining cyber and physical security is critical to ensuring system reliability and ongoing operations.
 
Goal focused on implementing updated security objectives. Emphasized securing our information systems and physical space, helping protect our most important assets.

Implementation of the 2019 Cyber Plan and Physical Security Plan, as presented to and approved by the Board of Directors, implementation of 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 Capital Project Plan. Achievement of targets for outage frequency were made more difficult for ITC Midwest in 2019 from previous years.
Category
 
Goal
 
Rationale for Goal
 
Rationale for Target
 
Potential Payout
 
2019 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 for ITCTransmission and METC, reduced from prior year for ITC Midwest; all targets aligned with industry benchmark data. Number of Forced, Sustained Line Outages, excluding the "External" cause classification, for:

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

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

ITC Midwest (66 or fewer, representing a reduction of 2 outages and top decile performance, no more than 55 at the 69kV level representing top quartile performance.);

Each target is worth 5%.
 
15
%
 
ITCTransmission - 10

METC - 17

ITC Midwest - 56/48

 
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 2019 Field O&M Initiatives for:

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

Each target worth 5%.

Payout reduced by 5% if not at or under Field O&M overall maintenance budget of $91.3M.
 
15
%
 
All high priority initiatives completed under budget
 
15%
 
Capital Project Plan
 
Performing necessary system upgrades is critical to ensuring system reliability, providing a robust transmission grid and delivering financial performance.
 
Target is based on accrued capital investment.

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

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

 
15 - 30%

 
$820M
 
30%
 
 
60
%
 
 
 
60%
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Bonus (as a percent of target bonus level)
 
100
%
 
 
 
100%
____________________________


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(1)
We utilize adjusted net income as a criterion in measuring achievement of financial goals for our annual corporate performance bonus. This non-GAAP financial measure reconciles to net income of our Regulated Operating Subsidiaries as follows:
(in millions)
2019
Net Income of Regulated Operating Subsidiaries
$
531

Adjustments Related to ROE Matters
(49
)
Other Adjustments
2

Adjusted Net Income
$
484

Additionally, our executives, including the NEOs, are eligible for an executive bonus multiplier. To further motivate management to provide value to the shareholder, we include a performance factor under which their ACPBs may be increased for outperformance by as much as 100% based on multiple measures, as follows:
Measure
Threshold
Achievement (1)
Multiplier
Weight
Result
Capital Investment Plan
$701M
$820M
2.00x
25%
0.50x
Cash from Operations Pre-Working Capital
$627M
$654M
1.75x
25%
0.44x
Adjusted Consolidated Net Income (2)
$367M
$379M
2.00x
25%
0.50x
Development Goals
1 Goal
Not Met
1.00x
25%
0.25x
Bonus Multiplier
 
 
 
 
1.69x
____________________________
(1)
Amounts presented are rounded to the nearest million.
(2)
We utilize adjusted consolidated net income as a criterion in measuring achievement of financial goals for the executive bonus multiplier. This non-GAAP financial measure reconciles to consolidated net income of ITC Holdings as follows:
(in millions)
2019
Net Income
$
428

Adjustments Related to ROE Matters
(49
)
Adjusted Consolidated Net Income
$
379

Each measure has an established scale, which includes a threshold level and below equating to a 1.00x multiplier, having no impact on the bonus award, to a maximum of 2.00x, which would increase the bonus by 100%. Achievement against performance scales related to each of the above metrics produced an executive bonus multiplier of 1.69x. This performance factor was applied to each executive’s ACPB to produce a final payment of approximately 169% of target.
Bonuses are based on a target bonus, which for each executive is a percentage of his or her base salary. The Committee considers each individual’s job responsibilities and the results of its benchmarking analysis when determining the base bonus percentage for the executive officers, including the NEOs, which we refer to as the “target bonus levels”. Target bonus levels for 2019 were 100% of base salary for each NEO.
Long-Term Incentive
The Committee provides and maintains a long-term equity incentive program under the 2017 Omnibus Plan. In February 2019, the Committee approved grants of SBUs and PBUs to employees, including the NEOs, based on our CEO’s recommendation (except for grants to the CEO), and also on the Committee’s assessment of the performance of the Company and the executive. Award opportunities for the NEOs were provided in a mix of PBUs (weighted 67%) and SBUs (weighted 33%). The PBUs can be earned for results in two equally-weighted measures, Total Shareholder Return (relative to Fortis’ peer group) and cumulative consolidated net income, over the three-year performance period. The PBU metrics were selected as Total Shareholder Return aligns with the Fortis shareholder experience and cumulative consolidated net income measures the sustained growth (organic and development), cost management and efficiency. Each unit is generally equivalent to one share of Fortis stock (as traded on the Toronto Stock Exchange) and earned units are payable in cash. Awards to the CEO were also presented to the Board of Directors by the Committee and ratified by the Board of Directors (other than the CEO). The amounts


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and more detailed terms of the 2019 SBU and PBU grants made under the 2017 Omnibus Plan are described in the narrative following the Grants of Plan-Based Awards Table. The awards were designed to reward, motivate and encourage long-term performance, act as a retention mechanism, and further align the interests of the NEOs with the interests of the shareholder. Total value for the award for each grantee was determined based on a percentage of salary. For the NEOs, when the 2019 awards were made, the award values were targeted to be:
NEO
Grant Value Percent of Salary
Ms. Apsey
250
%
Ms. Holloway
175
%
Mr. Jipping
175
%
Mr. Oginsky
175
%
Ms. Mason Soneral
175
%
In determining the size of grants under the long-term incentive program and the award mix, the Committee considered market practice, the recommendation of the CEO (with respect to grants other than to the CEO) in light of comparisons to benchmarking data, expense to the Company and the practice of other U.S. Fortis subsidiary companies.
On February 4, 2020, the Board approved the Executive Omnibus Plan. The Executive Omnibus Plan is a long-term equity incentive program that is available for employees with a title of Vice President or higher. The Committee has approved PBU grants, and may in the future approve grants of SBUs, PBUs, dividend equivalent units or cash incentive awards under the Executive Omnibus Plan.
Other Components of Our Executive Compensation Program
Pension Benefits. As is common in our industry and as established pursuant to our initial formation requirements included in the acquisition agreement with DTE Energy for ITCTransmission, we maintain a tax-qualified defined benefit retirement plan for eligible employees, comprised of a traditional pension component and a cash balance component. All employees, including the NEOs, participate in either the traditional component or the cash balance component. We have also established a supplemental nonqualified, noncontributory retirement benefit plan for selected management employees: the Executive Supplemental Retirement Plan, or ESRP, in which all of the NEOs participate. This plan provides for benefits that supplement those provided by our qualified defined benefit retirement plan. Benefits payable to the NEOs pursuant to the retirement plans are set by the terms of those plans. The Committee exercises no regular discretionary authority in the determination of benefits. The retirement plans may be modified, amended or terminated at any time, although no such action may reduce a NEO’s earned benefits. See “Pension Benefits” for information regarding participation by the NEOs in our retirement plans as well as a description of the terms of the plans.
Benefits and Perquisites. The NEOs participate in a variety of benefit programs, which are designed to enable us to attract and retain our workforce in a competitive marketplace. These programs include our Savings and Investment Plan, which consists of an employee deferral contribution component and an employer safe-harbor matching contribution component.
Our NEOs are provided a limited number of perquisites in addition to benefits provided to our other employees. The purpose of these perquisites is to minimize distractions from the NEOs’ attention to important Company initiatives, to facilitate their access to work functions and personnel, and to encourage interactions among NEOs and others within professional, business and local communities. NEOs are provided perquisites such as auto allowance, financial, estate and legal planning, income tax return preparation, annual physical, club memberships, and personal liability insurance. Additionally, we own aircraft to facilitate the business travel schedules of our executives and other employees, particularly to locations that do not provide efficient commercial flight schedules. Ms. Apsey and guests who travel with her are permitted to travel for personal business on our aircraft, with an annual maximum of 50 flight hours for such personal travel. Ms. Apsey incurs imputed income for all guests and herself for personal travel in the amount of the incremental cost to the Company of such travel.
We purchase tickets to various sporting, civic, cultural, charity and entertainment events. We use these tickets for business development, partnership building, charitable donations and community involvement. If not used for business purposes, we may make these tickets available to employees, including the NEOs, as a form of recognition and reward for their efforts. Because such tickets have already been purchased, we do not believe that there is any aggregate incremental cost to the Company, if a NEO uses a ticket for personal purposes.


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None of the NEOs are reimbursed for income taxes associated with the value of the perquisites. The Committee continues to monitor and review the Company’s perquisite program. Perquisites are further discussed in footnote 5 to the “Summary Compensation Table”.
Potential Severance Compensation. Pursuant to their employment agreements, each NEO is entitled to certain benefits and payments upon a termination of his or her employment. Benefits and payments to be provided vary based on the circumstances of the termination. We believe it is important to provide these protections in order to ensure our NEOs will remain engaged and committed to us during an acquisition of the Company or other transition in management. See “Employment Agreements and Potential Payments Upon Termination or Change in Control” for further detail on these employment agreements, including a discussion of the compensation to be provided upon termination or a change in control.
Stock Ownership Policy
The Board believes that having a share ownership policy is a key element of strong corporate governance and aligns the interests of management with the interests of Fortis shareholders. Under these guidelines, which became effective January 1, 2020, officers, including NEOs, must achieve and maintain the applicable level of Fortis stock ownership by the fifth anniversary of when the guidelines first became applicable to the individual. The current levels are as follows:
Position
Ownership Level
Chief Executive Officer
2x annual base salary
Executive and Senior Vice Presidents
1.5x annual base salary
Vice Presidents
1x annual base salary
The securities that qualify for the purpose of determining compliance with the policy are common shares of Fortis stock and the executive’s outstanding SBU awards. Share ownership levels include Fortis securities beneficially owned: (i) in a trust; (ii) by the executive’s spouse; and (iii) by the executive’s minor children. Any executive that fails to maintain minimum stock ownership under these guidelines, will not be eligible for future equity-based compensation awards until the later of (i) the end of the one-year period commencing on the date of such failure or (ii) such time as the executive is again in compliance with the guidelines. Each of the NEOs is in compliance with this policy.
Recoupment Policy
Our Recoupment Policy provides that in the event of any restatement of financial results, our NEOs will be required to reimburse the Company for an amount equal to the sum of:
•
Any bonus or other incentive-based or equity-based compensation received, earned or recognized by the NEO during the 12-month period following the first public issuance or filing with the SEC of the financial document embodying such financial reporting requirement in excess of the amount that would have been received, earned or recognized if the restated financial results had been released instead; and
•
Any profits realized by the NEO from the sale of securities of the Company during that 12-month period.
The Board of Directors or the Committee will determine, in its reasonable discretion, based on the circumstances, the amount, form and timing of recovery. The Recoupment Policy applies to any equity-based grants and incentive cash compensation awards.
Jipping Letter Agreement
In February 2019, Mr. Jipping entered into a letter agreement with the Company amending his employment agreement and long-term incentive awards, including his SBU and PBU awards granted under the 2017 Omnibus Plan. Under the terms of the letter agreement upon Mr. Jipping’s voluntary termination of employment, his SBU and PBU awards, which would otherwise be forfeited, will continue to vest on their normal schedule even if Mr. Jipping does not meet the retirement age, as defined in the 2017 Omnibus Plan, for continued vesting at the time of his termination. The letter agreement also removes Section 7c(ii)(B) of Mr. Jipping’s employment agreement which defines his rights to terminate the employment agreement if his job responsibilities and authority were substantially diminished.


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Governance and Human Resources Committee Report
The Governance and Human Resources Committee has reviewed and discussed this Compensation Discussion and Analysis with management and, based on the review and discussions with management, has recommended to the Board of Directors that the Compensation Discussion and Analysis be included in this report.
ALEXANDER I. GREENBAUM        BARRY V. PERRY            SANDRA E. PIERCE
A. DOUGLAS ROTHWELL        THOMAS G. STEPHENS
Summary Compensation
The following table provides a summary of compensation paid or accrued by the Company and its subsidiaries to or on behalf of the NEOs for services rendered by them during each of the last three calendar years, as required by SEC rules and regulations. The material terms of plans and agreements pursuant to which certain items set forth below were paid are discussed elsewhere in Compensation of Executive Officers and Directors.
Summary Compensation Table
Name
 
Year
 
Salary ($)
 
Bonus
($) (1)
 
Stock Awards ($) (2)
 
Non-Equity Incentive Plan Compensation ($) (3)
 
Change in Pension Value & Non-qualified Deferred Compensation Earnings ($)(4)
 
All Other Compensation ($) (5)
 
Total ($)
(a)
 
(b)
 
(c)
 
(d)
 
(e)
 
(f)
 
(g)
 
(h)
 
(i)
Linda H. Apsey,
President & CEO
 
2019
 
$
794,692

 
$
—

 
$
2,061,860

 
$
1,352,000

 
$
322,636

 
$
55,516

 
$
4,586,704

 
2018
 
752,712

 
—

 
1,747,386

 
1,169,118

 
123,927

 
66,909

 
3,860,052

 
2017
 
725,000

 
644,700

 
1,760,834

 
1,205,313

 
232,747

 
57,751

 
4,626,345

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gretchen L. Holloway
SVP & CFO
 
2019
 
388,115

 
—

 
703,598

 
659,100

 
147,032

 
36,362

 
1,934,207

 
2018
 
367,962

 
—

 
599,433

 
572,945

 
81,152

 
34,351

 
1,655,843

 
2017
 
317,981

 
265,000

 
552,539

 
581,875

 
80,454

 
33,126

 
1,830,975

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jon E. Jipping,
EVP & COO
 
2019
 
578,000

 
—

 
1,046,405

 
980,200

 
568,493

 
38,169

 
3,211,267

 
2018
 
553,674

 
—

 
899,149

 
859,418

 
63,980

 
37,869

 
2,414,090

 
2017
 
529,289

 
538,100

 
909,553

 
889,438

 
345,722

 
37,694

 
3,249,796

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Daniel J. Oginsky,
EVP & CAO
 
2019
 
483,988

 
—

 
875,001

 
819,650

 
236,208

 
36,742

 
2,451,589

 
2018
 
466,685

 
—

 
758,200

 
724,698

 
51,865

 
36,556

 
2,038,004

 
2017
 
445,327

 
444,150

 
765,053

 
748,125

 
177,356

 
35,972

 
2,615,983

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Christine Mason Soneral, SVP & General Counsel
 
2019
 
389,469

 
—

 
703,598

 
659,100

 
170,742

 
36,500

 
1,959,409

 
2018
 
377,204

 
—

 
612,373

 
585,333

 
66,424

 
35,250

 
1,676,584

 
2017
 
362,404

 
529,899

 
620,551

 
606,813

 
146,625

 
36,378

 
2,302,670

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


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Name
 
Year
 
Retention Bonus ($)
 
Other Bonuses ($)
 
Total Bonus ($)
 
 
 
 
 
 
 
 
 
Linda H. Apsey
 
2019
 
$
—

 
$
—

 
$
—

 
2018
 
—

 
—

 
—

 
2017
 
644,700

 
—

 
644,700

Gretchen L. Holloway
 
2019
 
—

 
—

 
—

 
2018
 
—

 
—

 
—

 
2017
 
140,000

 
125,000

 
265,000

Jon E. Jipping
 
2019
 
—

 
—

 
—

 
2018
 
—

 
—

 
—

 
2017
 
527,100

 
11,000

 
538,100

Daniel J. Oginsky
 
2019
 
—

 
—

 
—

 
2018
 
—

 
—

 
—

 
2017
 
444,150

 
—

 
444,150

Christine Mason Soneral
 
2019
 
—

 
—

 
—

 
2018
 
—

 
—

 
—

 
2017
 
529,899

 
—

 
529,899

(2)
The amounts reported in this column represent the fair value of PBU awards and SBU awards granted to the NEOs under the 2017 Omnibus Plan in accordance with FASB Accounting Standards Codification Topic 718, or ASC 718.
The grant date fair value of the SBU awards is based on the applicable share price on the grant date. The grant date fair value of the PBU awards is based on the applicable share price on the grant date and the expected payout of the performance and market conditions, with the market condition fair value determined using a Monte Carlo simulation valuation model. The SBU awards and PBU awards are liability awards, subject to remeasurement through the vesting date, and settled in cash, see “Grants of Plan-Based Awards.”
(3)
The amounts reported in this column include cash awards tied to the achievement of annual Company performance goals under our annual corporate performance bonus plan in effect for each of 2019, 2018 and 2017. For information regarding the corporate goals for 2019, see “Compensation Discussion and Analysis - Key Components of Our NEO Compensation Program - Annual Corporate Performance Bonus."
(4)
All amounts reported in this column pertain to the tax-qualified defined benefit pension plan and the supplemental nonqualified, noncontributory retirement plan maintained by the Company. None of the income on nonqualified deferred compensation was above-market or preferential. Variations in the amounts from year to year reflect an additional year of service and pay changes used in the accrued benefit, as well as changes in assumptions on which the benefits are calculated, for which the formula has not been materially revised. The discount rate used for the present value of accumulated benefits was 3.67% in 2017, 4.39% in 2018 and 3.44% in 2019. The long-term interest crediting rate for the cash balance component of the Retirement Plan and ESRP changed from 4.50% to 4.00% at year-end 2019.
(5)
All Other Compensation includes amounts for auto allowance, financial, estate and legal planning, income tax return preparation, annual physical, club memberships, event tickets, personal liability insurance, personal use of company aircraft and for other benefits such as Company contributions on behalf of the NEOs pursuant to the matching component of the Savings and Investment Plan. Perquisites have been valued for purposes of these tables on the basis of the aggregate incremental cost to the Company. The incremental cost of the personal use of the Company aircraft was determined based upon the Company’s expenses incurred in connection with the actual costs of maintenance, landing, parking, crew and catering and estimated fuel costs relating to Ms. Apsey’s hours of use of the aircraft. Fuel expense was determined by calculating the average fuel cost for the month and the average amount of fuel used per hour. These benefits and perquisites for 2019, 2018 and 2017 are itemized in the table below as required by applicable SEC rules.


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Name
 
Year
 
401(k) Match
 
Personal Use of Company Aircraft
 
Other Benefits
 
Total
Linda H. Apsey
 
2019
 
$
16,800

 
$
19,777

 
$
18,939

 
$
55,516

 
2018
 
14,750

 
25,074

 
27,085

 
66,909

 
2017
 
14,400

 
12,752

 
30,599

 
57,751

Gretchen L. Holloway
 
2019
 
15,100

 
—

 
21,262

 
36,362

 
2018
 
14,750

 
—

 
19,601

 
34,351

 
2017
 
14,400

 
—

 
18,726

 
33,126

Jon E. Jipping
 
2019
 
16,800

 
—

 
21,369

 
38,169

 
2018
 
16,500

 
—

 
21,369

 
37,869

 
2017
 
16,200

 
—

 
21,494

 
37,694

Daniel J. Oginsky
 
2019
 
15,100

 
—

 
21,642

 
36,742

 
2018
 
14,750

 
—

 
21,806

 
36,556

 
2017
 
14,400

 
—

 
21,572

 
35,972

Christine Mason Soneral
 
2019
 
15,100

 
—

 
21,400

 
36,500

 
2018
 
14,750

 
—

 
20,500

 
35,250

 
2017
 
14,400

 
—

 
21,978

 
36,378

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


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Grants of Plan-Based Awards
The following table sets forth information concerning each grant of an award made to a NEO during 2019.
Name
 
Grant Date
 
Award Type
 
Estimated Future Payouts Under Non-Equity Incentive Plan Awards
 
Estimated Future Payouts Under Equity Incentive Plan Awards
 
All Other Stock Awards: Number of Shares of Stock or Units (#)
 
Grant Date Fair Value of Stock and Option Awards ($)(3)
 
 
 
Threshold ($)
 
Target ($)(1)
 
Maximum ($)(1)
 
Threshold (#)
 
Target (#)(2)
 
Maximum (#)(2)
 
 
(a)
 
(b)
 
 
 
(c)
 
(d)
 
(e)
 
(f)
 
(g)
 
(h)
 
(i)
 
(j)
Linda H. Apsey
 
3/6/2019
 
SBU
 
$
—

 
$
—

 
$
—

 
—

 
—

 
—

 
20,141

 
$
666,667

 
3/6/2019
 
PBU
 
—

 
—

 
—

 
20,141

 
40,282

 
80,564

 
—

 
1,333,334

 
 
 
ACPB
 
—

 
800,000

 
1,600,000

 
—

 
—

 
—

 
—

 
—

Gretchen L. Holloway
 
3/6/2019
 
SBU
 
—

 
—

 
—

 
—

 
—

 
—

 
6,873

 
227,496

 
3/6/2019
 
PBU
 
—

 
—

 
—

 
6,873

 
13,746

 
27,492

 
—

 
454,993

 
 
 
ACPB
 
—

 
390,000

 
780,000

 
—

 
—

 
—

 
—

 
—

Jon E. Jipping
 
3/6/2019
 
SBU
 
—

 
—

 
—

 
—

 
—

 
—

 
10,222

 
338,348

 
3/6/2019
 
PBU
 
—

 
—

 
—

 
10,222

 
20,443

 
40,886

 
—

 
676,663

 
 
 
ACPB
 
—

 
580,000

 
1,160,000

 
—

 
—

 
—

 
—

 
—

Daniel J. Oginsky
 
3/6/2019
 
SBU
 
—

 
—

 
—

 
—

 
—

 
—

 
8,547

 
282,906

 
3/6/2019
 
PBU
 
—

 
—

 
—

 
8,548

 
17,095

 
34,190

 
—

 
565,845

 
 
 
ACPB
 
—

 
485,000

 
970,000

 
—

 
—

 
—

 
—

 
—

Christine Mason Soneral
 
3/6/2019
 
SBU
 
—

 
—

 
—

 
—

 
—

 
—

 
6,873

 
227,496

 
3/6/2019
 
PBU
 
—

 
—

 
—

 
6,874

 
13,746

 
27,496

 
—

 
454,993

 
 
 
ACPB
 
—

 
390,000

 
780,000

 
—

 
—

 
—

 
—

 
—

____________________________
(1)
The amount shown in Column (d) represents the potential payout for the ACPB based on “target bonus levels.” The amount payable assuming maximum achievement of all bonus goals is set forth in column (e). Actual dollar amounts paid are disclosed and reported in the “Summary Compensation Table” as Non-Equity Incentive Plan Compensation. For more information regarding the ACPBs, see “Compensation Discussion and Analysis — Key Components of Our NEO Compensation Program — Annual Corporate Performance Bonus.”
(2)
Payment of each PBU award is contingent on meeting performance targets based on (1) Fortis Total Shareholder Return in comparison to the Total Shareholder Return during the performance period for each of the companies that comprise the 2019 Fortis peer group and (2) cumulative consolidated net income for each fiscal year during the performance period. The performance measures are independent of each other. If threshold, target or maximum performance goals are attained in the performance period, 50%, 100% or 200% of the target amount, respectively, may be earned. If actual performance falls between threshold, target and maximum, the awards would be prorated between levels based on performance outcome. For more information regarding performance share awards, see “Grant of Plan-Based Awards - Performance-Based Unit Award Agreements.”
(3)
Grant Date Fair Value consists of SBUs and PBUs awarded under the 2017 Omnibus Plan with a grant date of March 6, 2019. The PBUs reflected here are recorded at fair value at the date of grant, which was $33.10 per share. The SBUs reflected here are recorded at fair value at the date of grant, which was $33.10 per share. Share fair values were converted from Canadian Dollars to US Dollars using the “Award Conversion Rate” defined in the 2017 Omnibus Plan.
The Committee has established long-term incentive targets as a percentage of the base salary for each NEO in consideration of benchmarking data on total direct compensation, the importance of the NEO’s position to the success of the Company, our need to create meaningful incentives to enhance performance and the culture of teamwork that makes our company successful. The Committee did not have a pre-established targeted allocation of total direct compensation.
The Committee had the power to award SBUs and PBUs in the form of equity or cash under the 2017 Omnibus Plan with the terms of each award set forth in a written agreement with the recipient. Grants made in 2019 to the NEOs were made under the 2017 Omnibus Plan pursuant to terms stated in the SBU and PBU award agreements.


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Performance-Based Unit Award Agreements
The PBU award agreements entered into with each NEO on March 6, 2019 (the “PBU Grant Date”) (each a “PBU Agreement”) provide generally that the award will vest on December 31, 2021 (the “PBU Vesting Date”) to the extent one or more of the performance goals are met and if the grantee continues to be employed by the Company through the PBU Vesting Date. One-half of the Target Number of PBUs shall be related to the Fortis Total Shareholder Return goal (the “TSR goal”) and one-half of the Target Number of PBUs shall be related to the Cumulative Consolidated Net Income goal (the “CCNI goal”). The PBUs will become earned as set forth in the following table:
Measurement Category
Goal at Threshold
Shares at Threshold
Goal at Target
Shares at Target
Goal at Maximum
Shares at Maximum
Fortis Total Shareholder Return
30th percentile
50% of TSR Target Units
50th 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, 2019 through December 31, 2021 (the “Payment Criteria Period”). The performance measures are independent of each other; that is, if the threshold level of one performance measure is attained, units relating to that measure will be “earned” (subject to vesting as otherwise provided in the PBU Agreement) even if the threshold level of the other performance measure is not attained. The number of PBUs that are “earned” with respect to each performance measure will be prorated between levels based on performance. The Committee will have discretion to reduce the number of PBUs earned under certain circumstances.
Total Shareholder Return of Fortis will be compared to each of the companies (the “Peer Companies”) listed in the Fortis Peer Group 2019 Report excluding any company that is no longer traded on the Toronto Stock Exchange or a “national securities exchange” at the end of the Payment Criteria Period. The Peer Companies currently consist of the following 25 U.S. and Canadian public utility companies:
Alliant Energy Corporation
Emera Incorporated
PG&E Corporation
Ameren Corporation
Entergy Corporation
Pinnacle West Capital Corporation
Atmos Energy Corporation
Evergy, Inc.
PPL Corporation
Canadian Utilities Limited
Eversource Energy
Public Service Enterprise Group Inc.
CenterPoint Energy Inc.
FirstEnergy Corp.
Sempra Energy
CMS Energy Corporation
Hydro One Limited
UGI Corporation
Consolidated Edison Inc.
NiSource Inc.
WEC Energy Group, Inc.
DTE Energy Company
OGE Energy Corp.
Xcel Energy Inc.
Edison International
 
 
The Total Shareholder Return of Fortis and the Peer Companies shall be computed in U.S. dollars as follows:
A: Calculate the Market Price as of the first day of the Payment Criteria Period (if necessary, converted into U.S. dollars based on the Award Conversion Rate as defined in the 2017 Omnibus Plan)
B: Calculate the Market Price as of the last day of the Payment Criteria Period (if necessary, converted into U.S. dollars based on the Award Conversion Rate)
C: Calculate the total dividends paid per share of its common stock (or equivalent security) during the Payment Criteria Period (if necessary, converted into U.S. dollars based on the Award Conversion Rate)
Total Shareholder Return = ((B - A) + C)/A
Consolidated Net Income for the Company for each calendar year in the Payment Criteria Period shall be equal to net income as set forth in the Company’s audited consolidated financial statements contained in its annual report on Form 10-K for such year, as adjusted for extraordinary items and changes in Return on Equity, in each case in the Committee’s discretion. Cumulative Consolidated Net Income for the Company during the Payment Criteria Period shall be the sum of the Consolidated Net Income for each of the three years in the Payment Criteria Period.
If the grantee ceases to be employed before the PBU Vesting Date due to death or disability, the grantee will receive, following the PBU Vesting Date, the number of PBUs to which the grantee would have otherwise been entitled if the grantee had remained employed through the PBU Vesting Date. If the grantee ceases to be employed before the PBU Vesting Date due to “Retirement” or “Involuntary Termination Without Cause”, (i) one-third of the


106

number of PBUs to which the grantee would have otherwise been entitled if the grantee had remained an employee through the PBU Vesting Date shall be deemed to have vested on the PBU Vesting Date if termination occurred on or after the one-year anniversary of the PBU Grant Date and before the two-year anniversary of the PBU Grant Date, and (ii) two-thirds of the number of PBUs to which the grantee would have otherwise been entitled if the grantee had remained an employee through the PBU Vesting Date shall be deemed to have vested on the PBU Vesting Date if termination occurred one or after the two-year anniversary of the PBU Grant Date but before the PBU Vesting Date. If termination occurs prior to the PBU Vesting Date other than as a result of death, disability, Retirement or Involuntary Termination Without Cause, grantee will forfeit the award. Under the terms of the Jipping Letter Agreement, upon Mr. Jipping’s voluntary termination of employment, his PBU awards, which would otherwise be forfeited, will continue to vest on their normal schedule even if Mr. Jipping does not meet the retirement age, as defined in the 2017 Omnibus Plan, for continued vesting at the time of his termination.
“Involuntary Termination Without Cause” means a termination of the grantee’s employment by the Company other than due to the grantee’s death, disability, Retirement, voluntary resignation or for “Cause” (as defined in the PBU Agreement). “Retirement” is defined to mean termination of grantee’s employment with the Company upon or after attaining “normal retirement age” (as defined in the International Transmission Company Retirement Plan).
Upon a “Change of Control”, as defined in the 2017 Omnibus Plan, all outstanding PBUs become redeemable on the trading day that is immediately prior to the effective date of the consummation of the event resulting in the Change of Control (the “Change of Control Redemption Date”). In the event of a Change of Control, the payout percentage for outstanding PBUs is the product of (i) the higher of (A) 100% of the target number of PBUs in the award or (B) the actual payout percentage based on the Committee’s assessment of performance of the payment criteria from the beginning of the Payment Criteria Period for the award through the date of the Change of Control, multiplied by (ii) a fraction, the numerator of which is the number of days elapsed in the Payment Criteria Period for the award through the date on which the Change of Control occurred and the denominator of which is the total number of days in the payment criteria period for the award.
Grantees are entitled to receive additional PBUs equal to the “dividend equivalent” when a cash dividend is paid on common shares of Fortis stock (each a “Common Share”). Such “dividend equivalent” shall be equal to a fraction where the numerator is the product of (a) the number of PBUs in the grantee’s account on the date that the dividends are paid, including PBUs previously credited as “dividend equivalents,” multiplied by (b) the dividend paid per Common Share and the denominator of which is the “Market Price” of one Common Share calculated on the date that dividends are paid, converted to U.S. dollars based on the Award Conversion Rate. All “dividend equivalent” PBUs shall have a PBU Vesting Date which is the same as the PBU Vesting Date for the PBUs in respect of which such additional PBUs are credited.
Service-Based Unit Award Agreements
The SBU award agreements entered into with each NEO on March 6, 2019 (the “SBU Grant Date”) (each a “SBU Agreement”) provide generally that, so long as the grantee remains employed by the Company, the SBUs fully vest upon the earlier of (i) December 31, 2021 (the “SBU Vesting Date”) or (ii) the grantee's death or disability. If the grantee ceases to be employed before the SBU Vesting Date due to “Retirement” or “Involuntary Termination Without Cause” (i) one-third of the number of SBUs to which the grantee would have otherwise been entitled shall vest if termination occurred one or after the one-year anniversary of the SBU Grant Date and before the two-year anniversary of the SBU Grant Date, and (ii) two-thirds of the number of SBUs to which the grantee would have otherwise been entitled shall vest if termination occurred on or after the two-year anniversary of the SBU Grant Date but before the SBU Vesting Date. If termination occurs prior to the SBU Vesting Date other than as a result of death, disability, Retirement or Involuntary Termination Without Cause, grantee will forfeit the award. Under the terms of the Jipping Letter Agreement upon Mr. Jipping’s voluntary termination of employment, his SBU awards, which would otherwise be forfeited, will continue to vest on their normal schedule even if Mr. Jipping does not meet the retirement age, as defined in the 2017 Omnibus Plan, for continued vesting at the time of his termination.
Upon a Change of Control, all unvested SBUs are deemed to be fully vested and redeemable on the Change of Control Redemption Date. “Retirement”, “Involuntary Termination Without Cause” and “Change of Control” are defined in the same manner as defined in the description of the PBU Agreement disclosed above. Grantees are entitled to receive additional dividend equivalent SBUs in the same manner as defined in the description of the PBU Agreement disclosed above.


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Outstanding Equity Awards at Fiscal Year-End
The following table provides information with respect to SBUs and PBUs that have not vested as of the end of 2019 held by the NEOs.
Name
Number of Shares or Units of Stock That Have Not Vested (#) (SBUs)
Market Value of Shares or Units of Stock That Have Not Vested ($) (SBUs) (1)
Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#) (PBUs)
Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($) (PBUs) (1)
(a)
(b)
(c)
(d)
(e)
Linda H. Apsey
18,358 (2)
$
762,220

36,716 (3)
1,524,448

20,673 (4)
858,351

41,346 (5)
1,716,686

Gretchen L. Holloway
6,298 (2)
261,491

12,595 (3)
522,944

7,055 (4)
292,907

14,109 (5)
585,806

Jon E. Jipping
9,446 (2)
392,215

18,893 (3)
784,437

10,492 (4)
435,632

20,983 (5)
871,214

Daniel J. Oginsky
7,966 (2)
330,732

15,931 (3)
661,455

8,773 (4)
364,249

17,547 (5)
728,551

Christine Mason Soneral
6,434 (2)
267,120

12,867 (3)
534,238

7,055 (4)
292,907

14,109 (5)
585,806

____________________________
(1)
Value was determined by multiplying the number of units that have not vested by the closing price of Fortis common stock on the NYSE as of December 31, 2019 ($41.52).
(2)
These unvested SBUs were granted in 2018 and generally vest on December 31, 2020. These SBU numbers include the original SBU grant plus dividend equivalent units earned.
(3)
These unvested PBUs were granted in 2018 and generally vest on December 31, 2020. These PBU numbers include the original PBU grant plus dividend equivalent units earned. The award contains performance conditions established by the Committee. In order for PBUs to vest such performance conditions must be achieved. Amounts reported reflect PBU payouts as if the target performance goals have been achieved.
(4)
These unvested SBUs were granted in 2019 and generally vest on December 31, 2021. These SBU numbers include the original SBU grant plus dividend equivalent units earned.
(5)
These unvested PBUs were granted in 2019 and generally vest on December 31, 2021. These PBU numbers include the original PBU grant plus dividend equivalent units earned.The award contains performance conditions established by the Committee. In order for PBUs to vest such performance conditions must be achieved. Amounts reported reflect PBU payouts as if the target performance goals have been achieved.
Equity grants made to NEOs in 2018 and 2019 were made pursuant to the 2017 Omnibus Plan. The terms of the grants are described above in the narrative discussion accompanying the “Grants of Plan-Based Awards” Table.


108

Option Exercises and Stock Vested
The following table provides information with respect to SBUs and PBUs held by the NEOs that vested during 2019:
 
Stock Awards
 
Name
Number of Shares or Units of Stock Acquired on Vesting (#)
Value of Shares or Units of Stock Realized on Vesting ($) (1)
(a)
(b)
(c)
Linda H. Apsey
21,699 (2)
$
875,052

53,807 (3)
$
2,170,185

Gretchen L. Holloway
6,808 (2)
$
274,575

16,885 (3)
$
681,005

Jon E. Jipping
11,207 (2)
$
451,999

27,794 (3)
$
1,121,012

Daniel J. Oginsky
9,427 (3)
$
380,217

23,378 (2)
$
764,807

Christine Mason Soneral
7,646 (2)
$
308,389

18,962 (3)
$
764,807

____________________________
(1)
Value is based on the 5-day VWAP price of common stock on the TSX on the vesting date, converted from Canadian Dollars to US Dollars using the “Award Conversion Rate” defined in the 2017 Omnibus Plan, which is $40.3327
(2)
Amounts reported reflect the vesting of SBUs granted March 8, 2017 and associated dividend equivalent units.
(3)
Amounts reported reflect the vesting of PBUs granted March 8, 2017 and associated dividend equivalent units. The award contains performance conditions established by the Committee. The performance period ended on December 31, 2019. The Committee certified the achievement of 124% of the applicable performance goals on February 4, 2020.



109

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
 
25.58

 
$
421,996

 
N/A
 
ESRP Shift
 
N/A

 
37,221

 
N/A
 
        Total Qualified Plan
 
 
 
459,217

 
N/A
 
ESRP
 
16.83

 
1,820,188

 
N/A
Gretchen Holloway
 
Cash Balance Component
 
15.95

 
279,327

 
N/A
 
        Total Qualified Plan
 
 
 
279,327

 
N/A
 
ESRP
 
4.91

 
285,187

 
N/A
Jon E. Jipping
 
Traditional Component
 
29.03

 
1,741,308

 
N/A
 
        Total Qualified Plan
 
 
 
1,741,308

 
N/A
 
ESRP
 
14.92

 
1,505,330

 
N/A
Daniel J. Oginsky
 
Cash Balance Component
 
15.20

 
343,226

 
N/A
 
        Total Qualified Plan
 
 
 
343,226

 
N/A
 
ESRP
 
15.20

 
1,200,313

 
N/A
Christine Mason Soneral
 
Cash Balance Component
 
12.29

 
275,932

 
N/A
 
        Total Qualified Plan
 
 
 
275,932

 
N/A
 
ESRP
 
12.28

 
668,476

 
N/A
____________________________
(1)
Credited service is estimated as of December 31, 2019 and represents the service reflected in the determination of benefits. For determining vesting, service with DTE Energy is counted for the Qualified Plan only.
For Ms. Apsey and Mr. Jipping, the credited service for the cash balance and traditional components of the Qualified Plan, respectively, includes service with DTE Energy. The Company began operations on February 28, 2003, following its acquisition of ITCTransmission from DTE Energy. As of that date, the benefits from DTE Energy’s qualified plan that had accrued, as well as the associated assets from DTE Energy’s pension trust, were transferred to the Qualified Plan. Therefore, even though DTE Energy service is included in determining the benefits under the traditional and cash balance components of the Qualified Plan, the benefits associated with this additional service do not represent a benefit augmentation, but rather a transfer of benefit liability and associated assets from DTE Energy’s qualified plan to the Qualified Plan. With respect to the ESRP, credited service includes Company service only for the period during which the NEO was an ESRP participant.
(2)
The “Present Value of Accumulated Benefit” is the estimated lump-sum equivalent value measured as of December 31, 2019 (the “measurement date” used for financial accounting purposes) of the benefit that was earned as of that date. Certain benefits are payable as an annuity only, not as a lump sum, and/or may not be payable for several years in the future. The values reflected are based on several assumptions. The date at which the present values were estimated was December 31, 2019. The rate at which future expected benefit payments were discounted in calculating present values was 3.44%, the same rate used for fiscal year-end 2019 financial accounting disclosure of the Qualified Plan. The future annual earnings rate on account balances under the cash balance and ESRP shift components of the Qualified Plan, and for ESRP benefits, was assumed to be 2.16% for 2020 and 4.00% thereafter.
We assumed no NEOs would die or become disabled prior to retirement or terminate employment with us prior to becoming eligible for benefits unreduced for early retirement. The assumed retirement age for each


110

executive was generally the earliest age at which benefits unreduced for early retirement were available under the respective plans. For the traditional component of the defined benefit plan, that age is the earlier of (1) age 58 with 30 years of service (including service with DTE Energy), or (2) age 60 with 15 years of service. For consistency, we generally use the same assumed retirement commencement age for other benefits, including benefits expressed as an account value where the concept of benefit reductions for early retirement is not meaningful. The assumed retirement benefit commencement ages were 58 for each NEO.
Post-retirement mortality was assumed to be in accordance with the Adjusted RP-2014 table projected for future mortality improvements with MP-2017 generational scale. Benefits under the traditional component of the Qualified Plan were assumed to be paid as a monthly annuity payable for the lifetime of the employee. For all other benefits, payment was assumed to be as a single lump sum, although other actuarially equivalent forms are available.
We maintain one tax-qualified noncontributory defined benefit pension plan and one supplemental nonqualified, noncontributory defined benefit retirement plan. First, we maintain the Qualified Plan, which provides funded, tax-qualified benefits up to the limits on compensation and benefits under the Internal Revenue Code. Generally, all of our salaried employees, including the NEOs, are eligible to participate.
We maintain the ESRP, in which all of our NEOs participate. The ESRP provides additional retirement benefits which are not tax qualified.
The following describes the Qualified Plan and the ESRP, and pension benefits provided to the NEOs under those plans.
Qualified Plan
There are two primary retirement benefit components of the Qualified Plan. Each NEO earns benefits from the Company under only one of these primary components.
Because our first operating utility subsidiary was acquired from DTE Energy, a component of the Qualified Plan bears relation to the DTE Energy Corporation Retirement Plan (the “DTE Plan”). Generally, persons who were participants in the “traditional component” of the DTE Plan as of February 28, 2003 (the date ITCTransmission was acquired from DTE Energy) earn benefits under the traditional component of our Qualified Plan. All other participants earn benefits under the cash balance component. Ms. Apsey also has benefits under the ESRP shift described below.
Benefits under the Qualified Plan are funded by an irrevocable tax-exempt trust. A NEO’s benefit under the Qualified Plan is payable from the assets held by the tax-exempt trust.
NEOs become fully vested in their normal retirement benefits described below with 3 years of service, including service with DTE Energy, or upon attainment of the plan’s normal retirement age of 65. If a NEO terminates employment with less than 3 years of service, the NEO is not vested in any portion of his or her benefit.
Traditional Component of Qualified Plan
Mr. Jipping participates in the traditional component of the Qualified Plan. The benefits are determined under the following formula, stated as an annual single life annuity payable in equal monthly installments at the normal retirement age of 65: 1.5% times average final compensation times credited service up to 30 years, plus 1.4% times average final compensation times credited service in excess of 30 years. Credited service includes service with DTE Energy. Although benefits under the formula are defined in terms of a single life annuity, other annuity forms (e.g., joint and survivor benefits) are available that have the same actuarial value as the single life annuity benefit. The benefits are not payable in the form of a lump sum.
Average final compensation is equal to one-fifth of the NEO’s salary (excluding any bonuses or special pay) during the 260 weeks of credited service, not necessarily consecutive, at any time during the NEO’s employment that results in the highest average.
Benefits provided under the Qualified Plan are based on compensation up to a compensation limit under the Internal Revenue Code (which was $280,000 in 2019 and is indexed in future years). In addition, benefits provided under the Qualified Plan may not exceed a benefit limit under the Internal Revenue Code (which was $225,000 payable as a single life annuity beginning at normal retirement age in 2019).


111

NEOs may retire with a reduced benefit as early as age 45 after 15 years of credited service. If a NEO has 30 years of credited service at retirement, the benefit that would be payable at normal retirement age is reduced for commencement ages below 58. The percentage of the normal retirement benefit payable at sample commencement ages is as follows:
Age 58 and older:    100%
Age 55:             85%
Age 50:             40%
If a NEO has less than 30 years but more than 15 years of credited service at retirement, the benefit that would be payable at normal retirement age is reduced for commencement ages below age 60. The percentage of the normal retirement benefit payable at sample commencement ages is as follows:
Age 60 and older:    100%
Age 55:             71%
Age 50:             40%
If a NEO terminates employment prior to earning 15 years of credited service, the annuity benefit may not commence prior to attaining age 65. If the NEO terminates employment after earning 15 years of credited service but below age 45, the benefit may commence as early as age 45. The percentage of the normal retirement benefit payable at sample commencement ages is as follows:
Age 65 and older:    100%
Age 60:            58%
Age 55:             36%
Age 50:             23%
Mr. Jipping’s annual accrued benefit payable monthly as an annuity for his lifetime, beginning at age 60, is approximately $118,000. He is fully vested.
Cash Balance Component of Qualified Plan
Mses. Apsey, Holloway and Mason Soneral and Mr. Oginsky participate in the cash balance component of the Qualified Plan. The benefits are stated as a notional account value.
Each year, a NEO’s account is increased by a “contribution credit” equal to 7% of pay. For this purpose, pay is equal to base salary plus bonuses and overtime up to the same compensation limit as applies under the traditional component of the Qualified Plan ($280,000 in 2019). Each year, a NEO’s account is also increased by an “interest credit” based on 30-year Treasury rates.
Upon termination of employment, a vested NEO may elect full payment of his or her account. Alternate forms of benefit (e.g., various forms of annuities) are available as well that have the same actuarial value as the account.
Mses. Apsey, Holloway and Mason Soneral and Mr. Oginsky are entitled to immediate payment of their account value on termination of employment, even if before normal retirement age. Ms. Apsey’s estimated account value as of year-end 2019 is approximately $411,000, Ms. Holloway’s is approximately $265,000, Ms. Mason Soneral’s is approximately $265,000, and Mr. Oginsky’s is approximately $328,000.
ESRP Shift Benefit in Qualified Plan
The ESRP provides notional account accruals similar to the cash balance component of the Qualified Plan. The “compensation credit” to the NEO’s notional account, analogous to the contribution credit in the cash balance component of the Qualified Plan, is equal to 9% of base salary plus actual bonus earned under the Company’s annual bonus plan. The “investment credit,” analogous to the interest credit in the cash balance component of the Qualified Plan, is similarly based on 30-year Treasury rates.
The ESRP shift benefit is an amount that would otherwise be payable from the ESRP, but is instead being paid from the Qualified Plan, subject to applicable qualified plan legal limits on the ability to discriminate in favor of highly paid employees. The NEO’s cash balance account is increased by any amounts shifted from the ESRP. The purpose of the benefit is to provide the NEO and the Company the tax advantages of providing benefits through a tax qualified plan.


112

Ms. Apsey has received ESRP shift additions to her Qualified Plan cash balance account. There was no shift of compensation credits for 2019, although previous shifts have continued to earn interest credits. As of year-end 2019, her ESRP shift balance was approximately $36,000.
Executive Supplemental Retirement Plan
The ESRP is a nonqualified retirement plan. Only selected executives participate, including all our NEOs. The purpose of the ESRP is to promote the success of the Company and its subsidiaries by providing the ability to attract and retain talented executives by providing such designated executives with additional retirement benefits.
The ESRP resembles the cash balance component of the Qualified Plan in that benefits are expressed as a notional account value and the vested account balance is payable as a lump sum on termination of employment, although an installment option of equivalent value is also available.
Each year, a NEO’s account is increased by a “compensation credit” equal to 9% of pay. For this purpose, pay is equal to base salary plus any bonus under the Company’s annual corporate performance bonus plan. There is no limit on compensation that may be taken into account as in the Qualified Plan. Each year, a NEO’s account is also increased by an “investment credit” equal to the same earnings rate as the interest credit in the cash balance component of the Qualified Plan, based on 30-year Treasury rates.
The plan has been in effect since March 1, 2003. Vesting occurs at 20% for each year of participation. All of our NEOs are fully vested.
As noted above in the description of the Qualified Plan, a portion of the ESRP account balance may be shifted to the cash balance component of the Qualified Plan each year, as permitted under the rules for qualified plans. Such a shift allows the NEOs to become immediately vested in the account values shifted and confers certain tax advantages to the NEOs and us. As of December 31, 2019, the ESRP account values, net of the amounts shifted to the Qualified Plan, are as follows:
Ms. Apsey
 
$
1,773,953

Ms. Holloway
 
270,720

Mr. Jipping
 
1,498,051

Mr. Oginsky
 
1,148,252

Ms. Mason Soneral
 
640,935

The ESRP is funded with a Rabbi Trust, which we cannot use for any purpose other than to satisfy the benefit obligations under the ESRP, except in the event of the Company’s bankruptcy, in which case the assets are available to general creditors.
Nonqualified Deferred Compensation
We maintain the Executive Deferred Compensation Plan under which nonqualified deferred compensation is permissible. Only selected officers of the Company, including the NEOs, are eligible to participate in this plan. NEOs are allowed to defer up to 100% of their salary and bonus. Investment earnings are based on the various investment options available under the plan and are selected by the individual NEOs. Distributions will generally be made at the NEO’s termination of employment for any reason. Mr. Jipping elected to participate in 2018 and his deferral was withheld in 2019. Mr. Jipping also elected to participate in 2019, and his deferral will be made in 2020 due to his 2019 bonus payment occurring in 2020. Mr. Jipping is the only NEO that participated in the Executive Deferred Compensation Plan in 2019.
Employment Agreements and Potential Payments Upon Termination or Change in Control
Employment Agreements
As referenced above, we entered into employment agreements with Ms. Apsey and Messrs. Jipping and Oginsky in December 2012 which superseded the employment agreements then in effect. In February 2015, we entered into an employment agreement with Ms. Mason Soneral which superseded her employment agreement then in effect. In July 2017, we entered into an employment agreement with Ms. Holloway, which superseded her employment agreement then in effect. Each employment agreement is subject to automatic one-year employment term renewals each year beginning on its second anniversary, unless either party provides the other with 30 days’ advance written notice of intent not to renew the employment term. Ms. Apsey’s agreement was modified in October 2016 in connection with her appointment as President and Chief Executive Officer and the initial term of the agreement expired on December 31, 2018 but is subject to the automatic one-year renewal provision described above. The following


113

describes the material terms of the employment agreements, as amended, with the NEOs who remained employed by the Company on December 31, 2019.
The employment agreements provide that each NEO will receive an annual base salary equal to their current base salary, which is subject to annual review and increase by our Board of Directors at its discretion. The employment agreements also provide that NEOs are eligible to receive an annual cash bonus, subject to our achievement of certain performance targets established by our Board of Directors, as detailed in “Compensation Discussion and Analysis.” The employment agreements also provide the NEOs with the right to participate in equity plans, employee benefit plans and retirement plans, including but not limited to welfare plans, retiree welfare benefit plans and defined benefit and defined contribution plans.
In addition, the NEOs’ employment agreements provide for payments by us of certain benefits upon termination of employment. The rights available at termination depend on the situation and circumstances surrounding the terminating event. The terms “Cause” and “Good Reason” are used in the employment agreements of each NEO and an understanding of these terms is necessary to determine the appropriate rights for which a NEO is eligible. The terms are defined as follows:
•
Cause means: a NEO’s continued failure substantially to perform his or her duties (other than as a result of total or partial incapacity due to physical or mental illness) for a period of 10 days following written notice by the Company to the NEO of such failure; dishonesty in the performance of the NEO’s duties; a NEO’s conviction of, or plea of nolo contender to, a crime constituting a felony or misdemeanor involving moral turpitude; willful malfeasance or willful misconduct in connection with a NEO’s duties; any act or omission which is injurious to the financial condition or business reputation of the Company; or violation of the non-compete or confidentiality provisions of the employment agreement.
•
Good reason means: a greater than 10% reduction in the total value of the NEO’s base salary, target bonus, and employee benefits; or if the NEO’s responsibilities and authority are substantially diminished.
If a NEO’s employment is terminated with cause by the Company or by the NEO without good reason, the NEO will generally only receive his or her accrued but unpaid compensation and benefits as of the date of his or her employment termination. If the NEO terminates due to death or disability (as defined in the employment agreements), the NEO (or the NEO’s spouse or estate) would also receive a pro rata portion of his or her current year annual target bonus.
If a NEO’s employment is terminated by the Company without cause or by the NEO for good reason, the NEO will receive the following, subject to the NEO’s execution of a release agreement and commencing generally on the earliest date that is permitted under Section 409A of the Internal Revenue Code:
•
any accrued but unpaid compensation and benefits including:
◦
Ms. Apsey: cash balance and ESRP shift under the Qualified Plan and vested portion of ESRP balance;
◦
Mr. Jipping: annual benefit under the traditional component of the Qualified Plan and vested portion of ESRP balance; and
◦
Mr. Oginsky, Ms. Mason Soneral and Ms. Holloway: cash balance under the Qualified Plan and vested portion of ESRP balance
•
continued payment of the NEO’s then-current base salary for two years;
•
if the termination is within six months before or two years after a “Change of Control” (as defined in the employment agreements), payment of an amount equal to two times the average of the ACPBs, that were payable to the NEO for the three fiscal years immediately preceding the fiscal year in which his or her employment terminates, payable in equal installments over the period in which continued base salary payments are made;
•
a pro rata portion of the ACPB for the year of termination, based upon the Company’s actual achievement of the performance targets for such year as determined under the annual corporate performance bonus plan and paid at the time that such bonus would normally be paid;
•
eligibility to continue coverage under our active medical, dental and vision plans subject to applicable COBRA rules; if such coverage is elected, we will reimburse the NEO for the shorter of 18 months, or until the NEO becomes eligible for coverage under another employer-sponsored group plan, in an amount equal to our periodic cost of such coverage for other executives, plus a tax gross-up amount;


114

•
outplacement services for up to two years; and
•
for Ms. Apsey, deemed satisfaction of the eligibility requirements of our Postretirement Welfare Plan for purposes of participation therein; and for Messrs. Jipping and Oginsky, participation in our Postretirement Welfare Plan only if, by the end of their specified severance period, they have achieved the necessary age and service credit otherwise necessary to meet the eligibility requirements. In addition, if we terminate our Postretirement Welfare Plan and, by application of the provisions described in the prior sentence, any of these NEOs would otherwise be entitled to retiree welfare benefits, we will establish other coverage for the NEO or the NEO will receive a cash payment equal to our cost of providing such benefits, in order to assist the NEO in obtaining other retiree welfare benefits.
In addition, while employed by us and for a period of two years after any termination of employment without cause by the Company (other than due to their disability) or for good reason by them and for a period of one year following any other termination of their employment, the NEOs will be subject to certain covenants not to compete with or assist other entities in competing with our business and not to encourage our employees to terminate their employment with us. At all times while employed and thereafter, all of the NEOs will also be subject to a covenant not to disclose confidential information.
In the event the NEO becomes subject to excise taxes under Section 4999 of the Internal Revenue Code as a result of payments and benefits received under the employment agreements or any other plan, arrangement or agreement with us, we will pay the NEO only that portion of such payments which are in total equal to one dollar less than the amount that would subject the NEO to the excise tax.
Payments in the Event of Termination
The benefits to be provided to the NEOs as a result of termination under various scenarios are detailed in the tables below. The tables assume that the termination occurred on December 31, 2019.
Linda H. Apsey - Termination Scenarios: Value of Potential Payments
Total Value of Severance, Benefits and Unvested Equity Awards(1)(2)
 
 
Voluntary Resignation
 
Involuntary For Cause
 
Involuntary Not-for-Cause or Voluntary Good Reason
 
Change In Control (pre-tax)(3)
 
Disability
 
Death (pre-retirement)(4)
Compensation
 
 
 
 
 
 
 
 
 
 
 
 
  Cash Severance
 
$
—

 
$
—

 
$
1,600,000

 
$
4,012,555

 
$
—

 
$
—

  Target Short-term Bonus
 
—

 
—

 
—

 
—

 
800,000

 
800,000

  Pro Rata Short-term (Annual) Incentive Comp
 
—

 
—

 
1,352,000

 
1,352,000

 
—

 
—

Retention Awards
 
 
 
 
 
—

 
—

 
—

 
—

  Service-Based Unit Awards (7)
 
—

 
—

 
254,075

 
1,620,567

 
1,620,567

 
1,620,567

  Performance-Based Unit Awards
 
—

 
—

 
508,149

 
1,585,573

 
3,241,151

 
3,241,151

Benefits and Perquisites
 
 
 
 
 
—

 
 
 
 
 
 
  Retirement Plan
 
—

 
—

 
—

 
—

 
—

 
—

  ESRP
 
—

 
—

 
—

 
—

 
—

 
—

  Perquisites
 
—

 
—

 
25,000

 
25,000

 
—

 
—

  Health & Welfare Benefits
 
—

 
—

 
29,255

 
29,255

 
—

 
—

  Postretirement Welfare Plan (5)
 
—

 
—

 
693,833

 
693,833

 
—

 
—

Total Payout:
 
$
—

 
$
—

 
$
4,462,312

 
$
9,318,783

 
$
5,661,718

 
$
5,661,718



115

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
 
$
—

 
$
—

 
$
780,000

 
$
1,662,104

 
$
—

 
$
—

  Target Short-term Bonus
 
—

 
—

 
—

 
—

 
390,000

 
390,000

  Pro Rata Short-term (Annual) Incentive Comp
 
—

 
—

 
659,100

 
659,100

 
—

 
—

  Service-Based Unit Awards (7)
 
—

 
—

 
87,164

 
554,417

 
554,417

 
554,417

  Performance-Based Unit Awards (8)
 
—

 
—

 
174,315

 
542,889

 
1,108,760

 
1,108,760

  280G Cutback
 
—

 
—

 
—

 
(981,273
)
 
—

 
—

Benefits and Perquisites
 
 
 
 
 
 
 
 
 
 
 
 
  Retirement Plan
 
—

 
—

 
—

 
—

 
—

 
—

  ESRP
 
—

 
—

 
—

 
—

 
—

 
—

  Perquisites
 
—

 
—

 
25,000

 
25,000

 
—

 
—

  Health & Welfare Benefits
 
—

 
—

 
29,462

 
29,462

 
—

 
—

Total Payout:
 
$
—

 
$
—

 
$
1,755,041

 
$
2,491,699

 
$
2,053,177

 
$
2,053,177

Jon E. Jipping - Termination Scenarios: Value of Potential Payments
Total Value of Severance, Benefits and Unvested Equity Awards(1)(2)
 
 
Voluntary Resignation or Voluntary Good Reason
 
Involuntary For Cause
 
Involuntary Not-for-Cause
 
Change In Control (pre-tax)(3)
 
Disability
 
Death (pre-retirement)(4)
Compensation
 
 
 
 
 
 
 
 
 
 
 
 
  Cash Severance
 
$
—

 
$
—

 
$
1,160,000

 
$
2,980,981

 
$
—

 
$
—

  Target Short-term Bonus
 
—

 
—

 
—

 
—

 
580,000

 
580,000

  Pro Rata Short-term (Annual) Incentive Comp
 
—

 
—

 
980,200

 
980,200

 
—

 
—

  Service-Based Unit Awards (7)
 
827,826

 
—

 
130,733

 
827,826

 
827,826

 
827,826

  Performance-Based Unit Awards (8)
 
—

 
—

 
261,479

 
811,854

 
1,655,659

 
1,655,659

Benefits and Perquisites
 
 
 
 
 
 
 
 
 
 
 
 
  Retirement Plan (6)
 
—

 
—

 
—

 
—

 
—

 
—

  ESRP
 
—

 
—

 
—

 
—

 
—

 
—

  Perquisites
 
—

 
—

 
25,000

 
25,000

 
—

 
—

  Health & Welfare Benefits
 
—

 
—

 
29,176

 
29,176

 
—

 
—

  Postretirement Welfare Plan (5)
 
—

 
—

 
723,287

 
723,287

 
 
 
 
Total Payout:
 
$
827,826

 
$
—

 
$
3,309,875


$
6,378,324

 
$
3,063,485

 
$
3,063,485



116

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
 
$
—

 
$
—

 
$
970,000

 
$
2,503,869

 
$
—

 
$
—

  Target Short-term Bonus
 
—

 
—

 
—

 
—

 
485,000

 
485,000

  Pro Rata Short-term (Annual) Incentive Comp
 
—

 
—

 
819,650

 
819,650

 
—

 
—

  Service-Based Unit Awards (7)
 
—

 
—

 
110,249

 
695,003

 
695,003

 
695,003

  Performance-Based Unit Awards (8)
 
—

 
—

 
220,485

 
682,547

 
1,389,995

 
1,389,995

Benefits and Perquisites
 
 
 
 
 
 
 
 
 
 
 
 
  Retirement Plan
 
—

 
—

 
—

 
—

 
—

 
—

  ESRP
 
—

 
—

 
—

 
—

 
—

 
—

  Perquisites
 
—

 
—

 
25,000

 
25,000

 
—

 
—

  Health & Welfare Benefits
 
—

 
—

 
30,401

 
30,401

 
—

 
—

Total Payout:
 
$
—

 
$
—

 
$
2,175,785

 
$
4,756,470

 
$
2,569,998

 
$
2,569,998

Christine Mason Soneral - Termination Scenarios: Value of Potential Payments
Total Value of Severance, Benefits and Unvested Equity Awards(1)(2)
 
 
Voluntary Resignation
 
Involuntary For Cause
 
Involuntary Not-for-Cause or Voluntary Good Reason
 
Change In Control (pre-tax)(3)
 
Disability
 
Death (pre-retirement)(4)
Compensation
 
 
 
 
 
 
 
 
 
 
 
 
  Cash Severance
 
$
—

 
$
—

 
$
780,000

 
$
2,038,491

 
$
—

 
$
—

  Target Short-term Bonus
 
—

 
—

 
—

 
—

 
390,000

 
390,000

  Pro Rata Short-term (Annual) Incentive Comp
 
—

 
—

 
659,100

 
659,100

 
—

 
—

  Service-Based Unit Awards (7)
 
—

 
—

 
89,047

 
560,063

 
560,063

 
560,063

  Performance-Based Unit Awards (8)
 
—

 
—

 
178,079

 
550,407

 
1,120,053

 
1,120,053

Benefits and Perquisites
 
 
 
 
 
 
 
 
 
 
 
 
  Retirement Plan
 
—

 
—

 
—

 
—

 
—

 
—

  ESRP
 
—

 
—

 
—

 
—

 
—

 
—

  Perquisites
 
—

 
—

 
25,000

 
25,000

 
—

 
—

  Health & Welfare Benefits
 
—

 
—

 
30,665

 
30,665

 
—

 
—

Total Payout:
 
$
—

 
$
—

 
$
1,761,891


$
3,863,726

 
$
2,070,116

 
$
2,070,116

____________________________
(1)
All scenarios include the value of severance. For Ms. Apsey and Mr. Jipping, the value of the Postretirement Welfare Plan is additionally included where applicable. The Pension Benefits Table assumes that none of the NEOs are terminated prior to retirement age and that benefits are paid once retirement commences (age 58 is assumed). All other accrued pension benefits, outside of present value reductions outlined in footnote (5), and additional pension benefits upon death, have not been included in these termination scenarios but can be found in the “Pension Benefits Table”.
(2)
Upon any termination of employment, benefits that are accrued but unpaid prior to that event are paid. These benefits are assumed to be $0 in the above tables.
(3)
Change in control values include severance amounts reflecting cutbacks to the extent employer payments exceed the executive respective limits. Ms. Holloway would be subject to an excise tax on the employer payments as of the assumed change in control date; therefore, a cutback in the amount of $981,273 has been reflected.


117

(4)
In the event of Mr. Jipping’s termination for death (pre-retirement), his spouse would receive half the 50% joint and survivor annuity under the traditional component of the Qualified Plan, also reduced to reflect a 90% early retirement factor that would apply at age 58 since Mr. Jipping does not have 30 years of service as of December 31, 2019. Under termination for death (pre-retirement), Ms. Apsey’s, Ms. Mason Soneral’s, Ms. Holloway’s, and Mr. Oginsky’s Qualified Plan benefits are payable immediately to the surviving spouse (if any) and ESRP benefits are payable to a designated beneficiary. The above termination scenarios do not reflect the reduction in present value of death benefits ($57,899 for Ms. Apsey, $28,636 for Ms. Holloway,$970,244 for Mr. Jipping, $66,948 for Mr. Oginsky, and $38,909 for Ms. Mason Soneral) compared to present value in the Pension Benefits Table.
(5)
The value of the Postretirement Welfare Plan benefit is included in involuntary termination not for cause and change in control scenarios for Ms. Apsey and Mr. Jipping since their employment agreement includes a provision for deemed satisfaction of the eligibility requirements when terminated under these scenarios. It is assumed each would commence their Postretirement Welfare Benefits at age 58. The rate at which future expected benefit payments were discounted in calculating the Postretirement Welfare Plan present values was 3.61%, the same rate used for fiscal year-end 2019 accounting disclosure of the Postretirement Welfare Plan.
(6)
The Pension Benefits Table assumes that Mr. Jipping would not be terminated before retirement age and no early retirement reduction was applied. In all termination scenarios, however, a 90% early retirement factor would apply at age 58 because Mr. Jipping has less than 30 years of service as of December 31, 2019. The above table does not reflect the reduction in the present value ($174,131 except for death) due to applying the 90% early retirement factor.
(7)
Under the 2017 Omnibus Plan, outstanding and unvested SBUs and respective dividend equivalents shall be deemed to be vested SBUs and redeemable on the Change of Control Redemption Date (as defined in the 2017 Omnibus Plan). In the case of Death or Disability (each as defined in the 2017 Omnibus Plan) termination, outstanding and unvested SBUs and respective dividend equivalents shall be deemed to be vested SBUs and redeemable on the date of the death or on the date on which the grantee’s service is terminated due to Disability. In the case of Retirement or Involuntary Termination Without Cause (each as defined in the 2017 Omnibus Plan) within one year of the grant date, outstanding and unvested SBUs and respective dividend equivalents shall be deemed to be forfeited. If Retirement or Involuntary Termination Without Cause occurs one year or more after the grant date, SBUs and respective dividend equivalents shall be deemed to have vested pro-rata based on the period served from the grant date to termination. For Mr. Jipping, pursuant to the Jipping Letter Agreement, upon a voluntary termination of employment, his SBUs, which would otherwise be forfeited, will continue to vest on their normal schedule.
(8)
Under the 2017 Omnibus Plan, outstanding and unvested PBU awards and respective dividend equivalents accelerate on a prorated basis under a Change in Control (as defined in the 2017 Omnibus Plan), based on the higher of (A) 100% of the target number of PBUs in the award or (B) the actual payout percentage based on the Committee’s assessment of performance of the payment criteria from the beginning of the Payment Criteria Period for the award through the date of the Change of Control (as defined in the 2017 Omnibus Plan). In the case of Death or Disability termination, the outstanding and unvested PBU awards and respective dividend equivalents will remain outstanding and be payable on the payout date of such awards subject to the achievement of the applicable payment criteria. Values shown in the tables above are based on target performance as an estimate of potential payments. In the case of Retirement or Involuntary Termination Without Cause within one year of the award grant date, outstanding and unvested PBU awards and respective dividend equivalents shall be deemed to be forfeited. If Retirement or Involuntary Termination Without Cause occurs one year or more after the grant date, PBU awards and respective dividend equivalents shall be deemed to have vested pro-rata based on the period served from grant date to termination. For Mr. Jipping, pursuant to the Jipping Letter Agreement, upon a voluntary termination of employment, his PBUs, which would otherwise be forfeited, will continue to vest on their normal schedule. The table does not reflect any value for Mr. Jipping’s outstanding and unvested PBUs as the payout is subject to achievement of the performance measures.
Upon death or disability, a NEO (or his or her estate) receives a pro rata portion of his or her current year target corporate performance bonus. All balances under the cash balance and ESRP shift components of the Qualified Plan, and the ESRP balance (vested portion only for disability), are immediately payable. If the NEO has 10 years of service after age 45, then the NEO (and his or her spouse) is eligible for retiree medical benefits.


118

Pay Ratio
As required by the U.S. Congress under the Dodd-Frank Wall Street Reform and Consumer Protection Act, and the SEC under Item 402(u) of Regulation S-K, we are providing the following information about the relationship of the annual total compensation of our employees and the annual total compensation of Linda H. Apsey our CEO:
For 2019, our last completed fiscal year:
the median of the annual total compensation of all employees of the Company (other than Ms. Apsey), was $155,054; and
the annual total compensation of Ms. Apsey as reported in the Summary Compensation Table was $4,586,704.
Based on this information, Ms. Apsey’s 2019 annual total compensation was estimated to be 30 times the median annual total compensation for all employees, other than Ms. Apsey.
Under Item 402(u), a company is permitted to identify its “median employee” once every three years if there has been no significant change to its employee population or employee compensation arrangements that would result in a significant change to its pay ratio disclosure. Since our previous year’s pay ratio disclosure there have been no such changes that would impact our previous pay ratio disclosure and, as a result, we have used the same “median employee” identified in our previous year’s disclosure.
Using our “median employee” and Ms. Apsey, we calculated the 2019 Summary Compensation Table values for each according to SEC rules.
Director Compensation
The following table provides information concerning the compensation of each person who served as a non-employee director of the Company during 2019.
Non-Employee Director Compensation Table
Name
 
Fees Earned or Paid in Cash ($) (1)
 
Total ($)
(a)
 
(b)
 
(h)
Robert A. Elliott
 
$
132,500

 
$
132,500

Albert Ernst
 
132,500

 
132,500

Rhys D. Evenden (2)
 
66,250

 
66,250

Alexander I. Greenbaum (3)
 
—

 
—

James P. Laurito
 
132,500

 
132,500

Barry V. Perry
 
132,500

 
132,500

Sandra E. Pierce
 
143,750

 
143,750

Kevin L. Prust
 
143,750

 
143,750

A. Douglas Rothwell
 
132,500

 
132,500

Thomas G. Stephens
 
143,750

 
143,750

Joseph L. Welch
 
170,000

 
170,000

____________________________
(1)
Includes annual Board retainer and committee chairmanship retainer, as well as a chairman fee (for Mr. Welch only).
(2)
The fees payable to Mr. Evenden are made directly to Betchworth Investment Pte. Ltd. Mr. Evenden left the Board in July 2019.
(3)
Mr. Greenbaum joined the Board in July 2019. Mr.Greenbaum waived all compensation due to him for his service on the Board.
Directors who are employees of the Company do not receive separate compensation for their services as a director. All non-employee directors are compensated under our non-employee director compensation policy, pursuant to which they are paid an annual cash retainer of $132,500. In addition, we pay an additional cash retainer


119

of $11,250 annually to the chair of each Board committee and $37,500 annually to our chairman. We do not pay per-meeting fees under the policy. Non-employee directors are reimbursed for their out-of-pocket expenses incurred for the performance of their duties as directors.
We maintain a Director Deferred Compensation Plan under which nonqualified deferred compensation is permissible. Only non-employee directors of the Company are eligible to participate in this plan. Directors are allowed to defer up to 100% of their annual board compensation. Investment earnings are based on the various investment options available under the plan, and are selected by the individual directors. Distributions will be made when the director ceases to serve on the Board and/or ceases to provide other non-employee consulting services to the Company or any Fortis entity. Messrs. Laurito, Stephens and Ms. Pierce participate in this plan.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.
The following table sets forth certain information regarding the ownership of our common stock and Fortis’ common stock as of February 1, 2020, except as otherwise indicated, by:
•
each of our current directors;
•
each of the persons named in the “Summary Compensation Table” under Item 11; and
•
all current directors and executive officers as a group.
The number of shares beneficially owned is determined under rules of the SEC and the information is not necessarily indicative of beneficial ownership for any other purpose. Under such rules, beneficial ownership includes any shares as to which the individual has sole or shared voting power or investment power and also any shares which the individual has the right to acquire on February 1, 2020 or within 60 days thereafter through the exercise of any stock option or other right. Unless otherwise indicated, each holder has sole investment and voting power with respect to the shares set forth in the following table:
Name of Beneficial Owner
Number of Company Shares
Beneficially Owned (#)
Percent of Class (%)
Number of Fortis shares Beneficially Owned (#)
 
Percent of Class (%)
Linda H. Apsey
—

—

53,889

 
*

Gretchen L. Holloway
—

—

12,929

 
*

Jon E. Jipping
—

—

120,000

 
*

Daniel J. Oginsky
—

—

72,621

 
*

Christine Mason Soneral
—

—

—

 
—

Robert A. Elliott
—

—

—

 
—

Albert Ernst
—

—

13,597

(1)
*

Alexander I. Greenbaum
—

—

—

 
—

James P. Laurito
—

—

19,408

 
*

Barry V. Perry
—

—

840,134

(2)
*

Sandra E. Pierce
—

—

—

 
—

Kevin L. Prust
—

—

—

 
—

A. Douglas Rothwell
—

—

—

 
—

Thomas G. Stephens
—

—

2,098

 
*

Joseph L. Welch
—

—

1,178,328

(3)
*

All current directors and executive officers as a group (16 persons)
—

—
%
2,313,004

 
*

* Less than one percent
____________________________
(1)
Includes 4,234 shares owned by the spouse of Mr. Ernst.


120

(2)
Includes 31,258 shares owned by the spouse of Mr. Perry as well as 519,462 shares that may be acquired upon exercise of options that are currently exercisable or become exercisable prior to April 2, 2020.
(3)
The amount shown in the table does not include 534,064 shares beneficially owned by the spouse of Mr. Welch. Mr. Welch has no voting or dispositive power with respect to such shares and he disclaims ownership of such shares.
ITC Investment Holdings, which owns all of our outstanding common stock, is 80.1% owned by FortisUS and 19.9% owned by Eiffel. FortisUS is a wholly-owned subsidiary of Fortis.
At December 31, 2019, there were no securities authorized for issuance under any compensation plans of ITC Holdings.
ITEM 13.     CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.
CERTAIN TRANSACTIONS
Pursuant to its charter, the Governance and Human Resources Committee is charged with monitoring and reviewing issues involving independence and potential conflicts of interest with respect to our directors and executive officers. The Committee also determines whether or not a particular relationship serves the best interest of the Company and its shareholder and whether the relationship should be continued or eliminated. In addition, our Code of Conduct and Ethics generally forbids conflicts of interest unless approved by the Board or a designated committee.
Although the Company does not have a written policy with regard to the approval of transactions between the Company and its executive officers and directors, each director and officer must annually submit a form to the General Counsel disclosing his or her conflicts or potential conflicts of interest or certifying that no such conflicts of interest exist. Throughout the year, if any transaction constituting a conflict of interest arises or circumstances otherwise change that would cause a director’s or officer’s annual conflict certification to become incorrect, the director or officer must inform the General Counsel of such circumstances. The Committee reviews existing conflicts as well as potential conflicts of interest and determines whether any further action is necessary, such as recommending to the Board whether a director or officer should be requested to offer his or her resignation. Where the Board makes a determination regarding a potential conflict of interest, a majority of the Board (excluding any interested member or members) shall decide upon an appropriate course of action. Additionally, any director or officer who has a question about whether a conflict exists must bring it to the attention of the Company’s General Counsel or Chairperson of the Committee.
Clayton Welch, Jennifer Welch, Jessica Uher and Katie Welch (each of whom is a son, daughter or daughter-in-law of Joseph L. Welch, the Company’s Chairman) were employed by us as a Senior Engineer, Fleet Manager, Manager of Corporate and Field Facilities, and Senior Accountant, respectively, during 2019 and continue to be employed by us. These individuals are employed on an “at will” basis and compensated on the same basis as our other employees of similar function, seniority and responsibility without regard to their relationship with Mr. Welch. These four individuals, none of whom resides with or is supported financially by Mr. Welch, received aggregate salary, bonus, long-term incentives and taxable perquisites for services rendered in the above capacities totaling $568,001 during 2019.
DIRECTOR INDEPENDENCE
Based on the absence of any material relationship between them and us, other than their capacities as directors, the Board has determined that Ms. Pierce and Messrs. Elliott, Ernst, Prust, Rothwell and Stephens are “independent” as defined in the Shareholders Agreement. In addition, our Board has determined that, as the committees are currently constituted, a majority of the members of the Audit and Risk Committee are “independent” as defined in the Shareholders Agreement. None of the directors determined to be independent is or ever has been employed by us. The Company has made charitable contributions of less than $1 million each to organizations with which certain of our directors have affiliations. The Board determined that these contributions would not interfere with the exercise of independent judgment by these directors in carrying out their responsibilities.
An independent director under the Shareholders Agreement is a director who meets all of the following requirements: (a) is elected by the shareholders of ITC Investment Holdings; (b) is designated as an independent director by the ITC Investment Holdings’ board and Company Board, or the shareholders of ITC Investment


121

Holdings; (c) is not a director that is nominated by Finn Investment Pte Ltd or any successor or permitted assign thereof and appointed as a member of the ITC Investment Holdings’ board and Company Board in accordance with the Shareholders Agreement; (d) is not and during the three years prior to being designated as an independent director has not been any of the following: (i) a director of FortisUS or any of its affiliates (other than ITC Investment Holdings or the Company); or (ii) an officer or employee of ITC Investment Holdings, the Company, FortisUS or any of their affiliates; and (e) would meet the definition of “independent director” under the NYSE Listed Company Manual if such director were a member of the board of directors of Fortis, FortisUS, ITC Investment Holdings, or the Company (assuming, in the case of FortisUS, ITC Investment Holdings and the Company, that such entities were listed on the NYSE).
Mr. Elliott serves on the board of directors of UNS Energy Corporation, a wholly-owned subsidiary of FortisUS. When determining Mr. Elliott’s independence, the board and shareholders agreed to waive the requirements set forth in the definition of independent director under the Shareholders Agreement which states that a director is not and during the three years prior to being designated as a director of the company has not served as a director of FortisUS or any of its affiliates.
ITEM 14.     PRINCIPAL ACCOUNTANT FEES AND SERVICES.
The following table provides a summary of the aggregate fees incurred for Deloitte’s services in 2019 and 2018:
 
2019
2018
Audit fees (1)
$
1,901,000

$
1,813,000

Audit-related fees (2)
54,000

97,000

Tax fees (3)
208,000

386,000

All other fees (4)
9,000

139,000

Total fees
$
2,172,000

$
2,435,000

____________________________
(1)
Audit fees were for professional services rendered for the audit of our consolidated financial statements and internal controls and reviews of the interim consolidated financial statements included in quarterly reports and services that are normally provided by Deloitte in connection with statutory and regulatory filing engagements.
(2)
Audit-related fees were for assurance and related services that are reasonably related to the performance of the audit or review of our consolidated financial statements and are not reported under “Audit Fees.” These services include audit of our employee benefit plans and services provided in connection with securities offerings.
(3)
Tax fees were professional services for federal and state tax compliance, tax advice and tax planning.
(4)
All other fees were for services other than the services reported above. These services included subscriptions to the Deloitte Accounting Research Tool, attendance at Deloitte sponsored conferences and labs, and due diligence work in 2018.
The Audit and Risk Committee of the Board of Directors does not consider the provision of the services described above by Deloitte to be incompatible with the maintenance of Deloitte’s independence.
The Audit and Risk Committee has adopted a pre-approval policy for all audit and non-audit services pursuant to which it pre-approves all audit and non-audit services provided by the independent registered public accounting firm prior to the engagement with respect to such services. To the extent that we need an engagement for audit and/or non-audit services between Audit and Risk Committee meetings, the Audit and Risk Committee chairman is authorized by the Audit and Risk Committee to approve the required engagement on its behalf.
The Audit and Risk Committee approved all of the services performed by Deloitte in 2019 pursuant to the pre-approval policy.


122

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, 2019 and 2018
 
 
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2019, 2018 and 2017
 
 
Consolidated Statements of Changes in Stockholder's Equity for the Years Ended December 31, 2019, 2018 and 2017
 
 
Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 2018 and 2017
 
 
Notes to Consolidated Financial Statements
 
(2)
Financial Statement Schedules
 
 
Schedule I — Condensed Financial Information of Registrant
 
 
All other schedules for which provision is made in Regulation S-X either (i) are not required under the related instructions or are inapplicable and, therefore, have been omitted, or (ii) the information required is included in the consolidated financial statements or the notes thereto that are a part hereof.
(b)
 
Exhibit Listing
The following exhibits are filed as part of this report or filed previously and incorporated by reference to the filing indicated. Our SEC file number is 001-32576.

Exhibit No.
 
Description of Exhibit
 
 
 
2.1

 
 
 
 
3.1

 
 
 
 
3.2

 
 
 
 
4.3

 
 
 
 
4.5

 
 
 
 
4.6

 
 
 
 
4.7

 
 
 
 
4.8

 
 
 
 
4.9

 
 
 
 
4.10

 
 
 
 


123

Exhibit No.
 
Description of Exhibit

4.12

 
 
 
 
4.14

 
 
 
 
4.17

 
 
 
 
4.18

 
 
 
 
4.19

 
 
 
 
4.20

 
 
 
 
4.23

 
 
 
 
4.24

 
 
 
 
4.25

 
 
 
 
4.26

 
 
 
 
4.27

 
 
 
 
4.28

 
 
 
 
4.29

 
 
 
 
4.30

 
 
 
 
4.31

 
 
 
 
4.32

 
 
 
 
4.33

 
 
 
 
4.34

 
 
 
 


124

Exhibit No.
 
Description of Exhibit

4.35

 
 
 
 
4.36

 
 
 
 
4.38

 
 
 
 
4.39

 
 
 
 
4.40

 
 
 
 
4.41

 
 
 
 
4.42

 
 
 
 
4.43

 
 
 
 
4.44

 
 
 
 
4.45

 
 
 
 
4.46

 
 
 
 
4.47

 
 
 
 
4.48

 
 
 
 
4.49

 
 
 
 
4.50

 
 
 
 
4.51

 
 
 
 
*10.27

 
 
 
 
10.51

 
 
 
 
*10.81

 
 
 
 


125

Exhibit No.
 
Description of Exhibit

*10.109

 
 
 
 
*10.110

 
 
 
 
*10.111

 
 
 
 
*10.120

 
 
 
 
*10.122

 
 
 
 
*10.150

 
 
 
 
*10.168

 
 
 
 
*10.172

 
 
 
 
*10.173

 
 
 
 
*10.176

 
 
 
 
*10.177

 
 
 
 
*10.178

 
 
 
 
*10.179

 
 
 
 
10.182

 
 
 
 
10.183

 
 
 
 
10.184

 
 
 
 
10.185

 
 
 
 
10.186

 
 
 
 


126

Exhibit No.
 
Description of Exhibit

10.187

 
 
 
 
10.188

 
 
 
 
*10.190

 
 
 
 
*10.191

 
 
 
 
*10.192

 
 
 
 
10.193

 
 
 
 
10.194

 
ITC Holdings Amendment and Restatement Agreement dated as of January 10, 2020, among ITC Holdings Corp., the banks, financial institutions and other institutional lenders listed on the respective signature pages thereof, Wells Fargo Bank, National Association, in its capacity as successor administrative agent and JPMorgan Chase Bank, N.A., in its capacity as resigning administrative agent, amending and restating as of January 10, 2020 in the form attached as Exhibit A thereto the Revolving Credit Agreement, dated as of October 23, 2017, among ITC Holdings Corp., the banks, financial institutions and other institutional party thereto, JPMorgan Chase Bank, N.A., as administrative agent for the lenders, JPMorgan Chase Bank, N.A., Barclays Bank PLC, Wells Fargo Securities, LLC, The Bank of Nova Scotia and Mizuho Bank, Ltd., as joint lead arrangers and joint bookrunners, Barclays Bank PLC and Wells Fargo Bank, National Association, as co-syndication agents and The Bank of Nova Scotia and Mizuho Bank, Ltd. as co-documentation agents (filed with the Registrant’s Form 8-K on January 10, 2020).
 
 
 
10.195

 
ITCTransmission Amendment and Restatement Agreement dated as of January 10, 2020, among International Transmission Company, the banks, financial institutions and other institutional lenders listed on the respective signature pages thereof, Wells Fargo Bank, National Association, in its capacity as successor administrative agent and JPMorgan Chase Bank, N.A., in its capacity as resigning administrative agent, amending and restating as of January 10, 2020 in the form attached as Exhibit A thereto the Revolving Credit Agreement, dated as of October 23, 2017, among International Transmission Company, the banks, financial institutions and other institutional party thereto, JPMorgan Chase Bank, N.A., as administrative agent for the lenders, JPMorgan Chase Bank, N.A., Barclays Bank PLC, Wells Fargo Securities, LLC, The Bank of Nova Scotia and Mizuho Bank, Ltd., as joint lead arrangers and joint bookrunners, Barclays Bank PLC and Wells Fargo Bank, National Association, as co-syndication agents and The Bank of Nova Scotia and Mizuho Bank, Ltd. as co-documentation agents (filed with the Registrant’s Form 8-K on January 10, 2020).
 
 
 
10.196

 
METC Amendment and Restatement Agreement dated as of January 10, 2020, among Michigan Electric Transmission Company, LLC, the banks, financial institutions and other institutional lenders listed on the respective signature pages thereof, Wells Fargo Bank, National Association, in its capacity as successor administrative agent and JPMorgan Chase Bank, N.A., in its capacity as resigning administrative agent, amending and restating as of January 10, 2020 in the form attached as Exhibit A thereto the Revolving Credit Agreement, dated as of October 23, 2017, among Michigan Electric Transmission Company, LLC, the banks, financial institutions and other institutional party thereto, JPMorgan Chase Bank, N.A., as administrative agent for the lenders, JPMorgan Chase Bank, N.A., Barclays Bank PLC, Wells Fargo Securities, LLC, The Bank of Nova Scotia and Mizuho Bank, Ltd., as joint lead arrangers and joint bookrunners, Barclays Bank PLC and Wells Fargo Bank, National Association, as co-syndication agents and The Bank of Nova Scotia and Mizuho Bank, Ltd. as co-documentation agents (filed with the Registrant’s Form 8-K on January 10, 2020).
 
 
 


127

Exhibit No.
 
Description of Exhibit

10.197

 
ITC Midwest Amendment and Restatement Agreement dated as of January 10, 2020, among ITC Midwest LLC, the banks, financial institutions and other institutional lenders listed on the respective signature pages thereof, Wells Fargo Bank, National Association, in its capacity as successor administrative agent and JPMorgan Chase Bank, N.A., in its capacity as resigning administrative agent, amending and restating as of January 10, 2020 in the form attached as Exhibit A thereto the Revolving Credit Agreement, dated as of October 23, 2017, among ITC Midwest LLC, the banks, financial institutions and other institutional party thereto, JPMorgan Chase Bank, N.A., as administrative agent for the lenders, JPMorgan Chase Bank, N.A., Barclays Bank PLC, Wells Fargo Securities, LLC, The Bank of Nova Scotia and Mizuho Bank, Ltd., as joint lead arrangers and joint bookrunners, Barclays Bank PLC and Wells Fargo Bank, National Association, as co-syndication agents and The Bank of Nova Scotia and Mizuho Bank, Ltd. as co-documentation agents (filed with the Registrant’s Form 8-K on January 10, 2020).
 
 
 
10.198

 
ITC Great Plains Amendment and Restatement Agreement dated as of January 10, 2020, among ITC Great Plains, LLC, the banks, financial institutions and other institutional lenders listed on the respective signature pages thereof, Wells Fargo Bank, National Association, in its capacity as successor administrative agent and JPMorgan Chase Bank, N.A., in its capacity as resigning administrative agent, amending and restating as of January 10, 2020 in the form attached as Exhibit A thereto the Revolving Credit Agreement, dated as of October 23, 2017, among ITC Great Plains, LLC, the banks, financial institutions and other institutional party thereto, JPMorgan Chase Bank, N.A., as administrative agent for the lenders, JPMorgan Chase Bank, N.A., Barclays Bank PLC, Wells Fargo Securities, LLC, The Bank of Nova Scotia and Mizuho Bank, Ltd., as joint lead arrangers and joint bookrunners, Barclays Bank PLC and Wells Fargo Bank, National Association, as co-syndication agents and The Bank of Nova Scotia and Mizuho Bank, Ltd. as co-documentation agents (filed with the Registrant’s Form 8-K on January 10, 2020).
 
 
 
10.199

 
 
 
 
*10.200

 
 
 
 
*10.201

 
 
 
 
*10.202

 
 
 
 
21

 
 
 
 
31.1

 
 
 
 
31.2

 
 
 
 
32

 
 
 
 
101.INS

 
XBRL Instance Document - the instance document does not appear in the Interactive Data file because its XBRL tags are embedded within the Inline XBRL document
 
 
 
101.SCH

 
Inline XBRL Taxonomy Extension Schema
 
 
 
101.CAL

 
Inline XBRL Taxonomy Extension Calculation Linkbase
 
 
 
101.DEF

 
Inline XBRL Taxonomy Extension Definition Database
 
 
 
101.LAB

 
Inline XBRL Taxonomy Extension Label Linkbase
 
 
 
101.PRE

 
Inline XBRL Taxonomy Extension Presentation Linkbase
 
 
 
104

 
The cover page from the Company’s Annual Report on Form 10-K for the year ended December 31, 2019, formatted in Inline XBRL
____________________________
*
 
Management contract or compensatory plan or arrangement.


128

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)
2019
 
2018
ASSETS
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
2

 
$
3

Accounts receivable from subsidiaries
17

 
26

Intercompany tax receivable from subsidiaries
3

 
15

Income tax receivable
—

 
1

Prepaid and other current assets
5

 
1

Total current assets
27

 
46

Other assets
 
 
 
Investment in subsidiaries
5,136

 
4,733

Deferred income taxes
140

 
104

Other assets
99

 
90

Total other assets
5,375

 
4,927

TOTAL ASSETS
$
5,402

 
$
4,973

LIABILITIES AND STOCKHOLDER’S EQUITY
 
 
 
Current liabilities
 
 
 
Accrued compensation
$
61

 
$
30

Accrued interest
21

 
26

Debt maturing within one year
200

 
—

Other current liabilities
11

 
12

Total current liabilities
293

 
68

Accrued pension and postretirement liabilities
73

 
68

Other liabilities
37

 
19

Long-term debt (net of deferred financing fees and discount of $17 and $20, respectively)
2,767

 
2,767

STOCKHOLDER’S EQUITY
 
 
 
Common stock, without par value, 235,000,000 shares authorized, 224,203,112 shares issued and outstanding at December 31, 2019 and 2018
892

 
892

Retained earnings
1,333

 
1,155

Accumulated other comprehensive income
7

 
4

Total stockholder’s equity
2,232

 
2,051

TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY
$
5,402

 
$
4,973

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


129

SCHEDULE I — Condensed Financial Information of Registrant
ITC HOLDINGS CORP.
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (PARENT COMPANY ONLY)
 
Year Ended December 31,
(In millions)
2019
 
2018
 
2017
Other income (expense), net
$
5

 
$
1

 
$
2

General and administrative expense
(25
)
 
(7
)
 
(11
)
Taxes other than income taxes
(2
)
 
—

 
(2
)
Interest expense
(119
)
 
(114
)
 
(120
)
LOSS BEFORE INCOME TAXES
(141
)
 
(120
)
 
(131
)
INCOME TAX BENEFIT
(44
)
 
(30
)
 
(6
)
LOSS AFTER TAXES
(97
)
 
(90
)
 
(125
)
EQUITY IN SUBSIDIARIES’ NET EARNINGS
525

 
420

 
444

NET INCOME
428

 
330

 
319

OTHER COMPREHENSIVE INCOME (LOSS)
 
 
 
 
 
Derivative instruments (net of tax of $1 for the year ended December 31, 2019 and less than $1 for the year ended December 31, 2018)
3

 
1

 
—

TOTAL OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
3

 
1

 
—

TOTAL COMPREHENSIVE INCOME
$
431

 
$
331

 
$
319

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


130

SCHEDULE I — Condensed Financial Information of Registrant
ITC HOLDINGS CORP.
CONDENSED STATEMENTS OF CASH FLOWS (PARENT COMPANY ONLY)
 
Year Ended December 31,
(In millions)
2019
 
2018
 
2017
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
 
 
Net income
$
428

 
$
330

 
$
319

Adjustments to reconcile net income to net cash used in operating activities:
 
 
 
 
 
Equity in subsidiaries' earnings
(525
)
 
(420
)
 
(444
)
Dividends from subsidiaries
3

 
26

 
3

Deferred and other income taxes
(51
)
 
(23
)
 
67

Net intercompany tax payments from (to) subsidiaries
14

 
59

 
(13
)
Other
6

 
2

 
5

Changes in assets and liabilities, exclusive of changes shown separately:
 
 
 
 
 
Accounts receivable from subsidiaries
9

 
(4
)
 
(4
)
Intercompany tax receivable from subsidiaries
11

 
(13
)
 
2

Income tax receivable
1

 
14

 
2

Intercompany tax payable to subsidiaries
—

 
—

 
(72
)
Accrued compensation
31

 
2

 
14

Other current and non-current assets and liabilities, net
9

 
13

 
—

Net cash used in operating activities
(64
)
 
(14
)
 
(121
)
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
 
 
Equity contributions to subsidiaries
(120
)
 
(202
)
 
(148
)
Return of capital from subsidiaries
239

 
324

 
296

Other
(1
)
 
(1
)
 
(9
)
Net cash provided by investing activities
118

 
121

 
139

CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
 
 
Issuance of long-term debt, net of discount
—

 
—

 
999

Borrowings under revolving credit agreement
72

 
37

 
97

Borrowings under term loan credit agreements
200

 
—

 
200

Net issuance of commercial paper, net of discount
200

 
—

 
(148
)
Retirement of long-term debt — including extinguishment of debt costs
(203
)
 
—

 
(437
)
Repayments of revolving credit agreement
(75
)
 
—

 
(170
)
Repayments of term loan credit agreement
—

 
—

 
(200
)
Dividends to ITC Investment Holdings
(250
)
 
(200
)
 
(300
)
Other
—

 
(1
)
 
(2
)
Net cash (used in) provided by financing activities
(56
)
 
(164
)
 
39

NET (DECREASE) INCREASE IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH
(2
)
 
(57
)
 
57

CASH, CASH EQUIVALENTS AND RESTRICTED CASH — Beginning of period
4

 
61

 
4

CASH, CASH EQUIVALENTS AND RESTRICTED CASH — End of period
$
2

 
$
4

 
$
61

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


131

SCHEDULE I — Condensed Financial Information of Registrant
ITC HOLDINGS CORP.
NOTES TO CONDENSED FINANCIAL STATEMENTS (PARENT COMPANY ONLY)
1.     GENERAL
For ITC Holdings Corp.’s (“ITC Holdings,” “we,” “our” and “us”) presentation (Parent Company only), the investment in subsidiaries is accounted for using the equity method. The condensed parent company financial statements and notes should be read in conjunction with the consolidated financial statements and notes of ITC Holdings appearing in this Annual Report on Form 10-K.
As a holding company with no business operations, ITC Holdings’ assets consist primarily of investments in our subsidiaries. ITC Holdings’ material cash inflows are only from dividends and other payments received from our subsidiaries, the proceeds raised from the sale of debt securities, issuances under our commercial paper program and borrowings under our revolving credit agreement. ITC Holdings may not be able to access cash generated by our subsidiaries in order to fulfill cash commitments. The ability of our subsidiaries to make dividend and other payments to us is subject to the availability of funds after taking into account their respective funding requirements, the terms of their respective indebtedness, the regulations of the FERC under the FPA and applicable state laws. In addition, there are practical limitations on using the net assets of each of our Regulated Operating Subsidiaries as of December 31, 2019 for dividends based on management's intent to maintain the FERC-approved capital structure targeting 60% equity and 40% debt for each of our Regulated Operating Subsidiaries. These net assets are included in Schedule I as the line-item “Investments in subsidiaries.” Each of our subsidiaries, however, is legally distinct from us and has no obligation, contingent or otherwise, to make funds available to us.
2.     DEBT
As of December 31, 2019, the maturities of our debt outstanding were as follows:
(In millions)
 
2020
$
200

2021
200

2022
534

2023
250

2024
400

2025 and thereafter
1,400

Total
$
2,984


Refer to Note 11 to the consolidated financial statements for additional information on the ITC Holdings Senior Notes, the ITC Holdings Revolving and Term Loan Credit Agreements, the ITC Holdings Commercial Paper Program and the ITC Holdings Derivative Instruments and Hedging Activities.
Based on the borrowing rates obtained from third party lending institutions currently available for bank loans with similar terms and average maturities from active markets, the fair value of the ITC Holdings Senior Notes was $2,752 million and $2,764 million at December 31, 2019 and 2018, respectively. The total book value of the ITC Holdings Senior Notes, net of discount and deferred financing fees, was $2,533 million and $2,730 million at December 31, 2019 and 2018, respectively. At December 31, 2019 and 2018, we had $234 million and $37 million respectively, outstanding under our revolving and term loan credit agreements, which are variable rate loans. The fair value of these loans approximates book value based on the borrowing rates currently available for variable rate loans obtained from third party lending institutions. At December 31, 2019, ITC Holdings had interest rate swaps with a total notional amount of $200 million, and the fair value of these interest rate swaps of $3 million was recorded in other current assets in the condensed statements of financial position. The fair values of the ITC Holdings Senior Notes, revolving and term loan credit agreements and interest rate swaps represent Level 2 under the three-tier hierarchy described in Note 14 to the consolidated financial statements. At December 31, 2019 ITC Holdings had $200 million commercial paper issued and outstanding under the commercial paper program. At December 31, 2018 ITC Holdings had no commercial paper issued and outstanding under the commercial paper program. Due to the short-term nature of these financial instruments, the carrying value approximates fair value.


132

3.     RELATED-PARTY TRANSACTIONS
Our related-party transactions during were as follows:
 
Year Ended December 31,
(In millions)
2019
 
2018
 
2017
Equity contributions to subsidiaries
$
120

 
$
202

 
$
148

Dividends from subsidiaries (a)
3

 
26

 
3

Return of capital from subsidiaries (a)
239

 
324

 
296

 
 
 
 
 
 
Net income tax payments (to) from: (b)
 
 
 
 
 
ITCTransmission
$
7

 
$
39

 
$
4

METC
4

 
7

 
1

ITC Midwest
3

 
3

 
5

ITC Great Plains
(1
)
 
9

 
11

ITC Interconnection
1

 
1

 
1

Other (c)
—

 
—

 
(35
)
____________________________
(a)
Includes ITCTransmission, MTH, ITC Midwest and other subsidiaries.
(b)
The net income tax payments were pursuant to intercompany tax sharing arrangements, and the total of these tax payments is presented as a net cash outflow or inflow from operating activities in the condensed parent company statements of cash flows. Other reconciling items between the parent company and the consolidated tax liabilities are presented as deferred and other income taxes in the adjustments to reconcile net income to net cash provided by operating activities. Additionally, ITC Holdings paid its subsidiaries for NOLs utilized by the consolidated group.
(c)
Includes all of our non-regulated subsidiaries.
Net Intercompany Receivables and Payables
We may incur charges from our subsidiaries for general corporate expenses incurred. In addition, we may perform additional services for, or receive additional services from our subsidiaries. These transactions are in the normal course of business and payments for these services are settled through accounts receivable and accounts payable, as necessary. We generally settle our intercompany balances with our affiliates on a net basis monthly.
Intercompany Tax Sharing Arrangement
As discussed in Note 1 to the condensed financial statements of the parent company, we are a holding company with no business operations. We file consolidated income tax returns that include our affiliates, which are taxed as a corporation for federal and Michigan income tax purposes. We operate under an intercompany tax sharing arrangement with our subsidiaries and as a result may receive or pay federal and state income tax based on their stand-alone company tax positions.
Retirement Benefits
We are the plan sponsor for a pension plan, other postretirement plans and a defined contribution plan. The benefits-related expenses recorded by our affiliates result from the inclusion of benefit costs as a component of the total charge for services performed by our employees under the cost assignment and allocation methods used by us and our subsidiaries.


133

4.    SUPPLEMENTAL FINANCIAL INFORMATION
Reconciliation of Cash, Cash Equivalents and Restricted Cash
The following table provides a reconciliation of cash, cash equivalents and restricted cash reported on the condensed statements of financial position that sum to the total of the same such amounts shown in the condensed statements of cash flows:
 
December 31,
(In millions)
2019
 
2018
 
2017
 
2016
Cash and cash equivalents
$
2

 
$
3

 
$
60

 
$
4

Restricted cash included in:
 
 
 
 
 
 
 
Other non-current assets
—

 
1

 
1

 
—

Total cash, cash equivalents and restricted cash
$
2

 
$
4

 
$
61

 
$
4


Restricted cash included in other non-current assets primarily represents cash on deposit to pay for vegetation management, land easements and land purchases for the purpose of transmission line construction.
Supplementary Cash Flows Information
 
Year Ended December 31,
(In millions)
2019
 
2018
 
2017
Supplementary cash flows information:
 
 
 
 
 
Interest paid
$
117

 
$
117

 
$
115

Income tax refunds received
3

 
13

 
1

Supplementary non-cash investing and financing activities:
 
 
 
 
 
Equity transfers from subsidiaries
—

 
—

 
(2
)

ITEM 16.     FORM 10-K SUMMARY.
Not applicable.


134

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 12, 2020.
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 12, 2020
Linda H. Apsey
Officer (principal executive officer)
 
 
 
 
/s/ GRETCHEN L. HOLLOWAY
Senior Vice President and Chief Financial Officer
February 12, 2020
Gretchen L. Holloway
 (principal financial and accounting officer)
 
 
 
 
/s/ JOSEPH L. WELCH
Director and Chairman
February 12, 2020
Joseph L. Welch
 
 
 
 
 
/s/ ROBERT A. ELLIOTT
Director
February 12, 2020
Robert A. Elliott
 
 
 
 
 
/s/ ALBERT ERNST
Director
February 12, 2020
Albert Ernst
 
 
 
 
 
/s/ ALEXANDER I. GREENBAUM
Director
February 12, 2020
Alexander I. Greenbaum
 
 
 
 
 
/s/ JAMES P. LAURITO
Director
February 12, 2020
James P. Laurito
 
 
 
 
 
/s/ BARRY V. PERRY
Director
February 12, 2020
Barry V. Perry
 
 
 
 
 
/s/ SANDRA E. PIERCE
Director
February 12, 2020
Sandra E. Pierce
 
 
 
 
 
/s/ KEVIN L. PRUST
Director
February 12, 2020
Kevin L. Prust
 
 
 
 
 
/s/ A. DOUGLAS ROTHWELL
Director
February 12, 2020
A. Douglas Rothwell
 
 
 
 
 
/s/ THOMAS G. STEPHENS
Director
February 12, 2020
Thomas G. Stephens
 
 


135
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