10-K 1 itc2016123110k.htm 10-K Document

 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(Mark One)
þ
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the fiscal year ended December 31, 2016
OR
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number: 001-32576
ITC HOLDINGS CORP.
(Exact Name of Registrant as Specified in Its Charter)
Michigan
(State or Other Jurisdiction of
Incorporation or Organization)
 
32-0058047
(I.R.S. Employer
Identification No.)
27175 Energy Way
Novi, Michigan 48377
(Address Of Principal Executive Offices, Including Zip Code)
(248) 946-3000
(Registrant’s Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
Common stock, without par value
 
Name of Each Exchange on Which Registered
None
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act of 1933. Yes o No þ
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934. Yes o No þ
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 þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information, statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer þ
 
Accelerated filer o
 
Non-accelerated filer o
 
Smaller Reporting Company o
 
 
 
 
(Do not check if a smaller reporting company)
 
 
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
The aggregate market value of the registrant’s common stock held by non-affiliates on June 30, 2016 was approximately $7 billion, based on the closing sale price as reported on the New York Stock Exchange. For purposes of this computation, all executive officers, directors and 10% beneficial owners of the registrant are assumed to be affiliates. Such determination should not be deemed an admission that such officers, directors and beneficial owners are, in fact, affiliates of the registrant.
All shares of outstanding common stock of ITC Holdings Corp. are held by its parent company, ITC Investment Holdings Inc., which is an indirect subsidiary of Fortis Inc. There were 224,203,112 shares of common stock, no par value, outstanding as of February 16, 2017.

DOCUMENTS INCORPORATED BY REFERENCE
None
 


ITC Holdings Corp.
Form 10-K for the Fiscal Year Ended December 31, 2016
INDEX

 
 
Page
 
 
 
 
 
 
 
 
 



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DEFINITIONS
Unless otherwise noted or the context requires, all references in this report to:
ITC Holdings Corp. and its subsidiaries
•
“ITC Great Plains” are references to ITC Great Plains, LLC, a wholly-owned subsidiary of ITC Grid Development, LLC;
•
“ITC Grid Development” are references to ITC Grid Development, LLC, a wholly-owned subsidiary of ITC Holdings;
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“ITC Holdings” are references to ITC Holdings Corp. and not any of its subsidiaries;
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“ITC Interconnection” are references to ITC Interconnection LLC, a wholly-owned subsidiary of ITC Grid Development, LLC;
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“ITC Midwest” are references to ITC Midwest LLC, a wholly-owned subsidiary of ITC Holdings;
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“ITCTransmission” are references to International Transmission Company, a wholly-owned subsidiary of ITC Holdings;
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“METC” are references to Michigan Electric Transmission Company, LLC, a wholly-owned subsidiary of MTH;
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“MISO Regulated Operating Subsidiaries” are references to ITCTransmission, METC and ITC Midwest together;
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“MTH” are references to Michigan Transco Holdings, LLC, the sole member of METC and an indirect wholly-owned subsidiary of ITC Holdings;
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“Regulated Operating Subsidiaries” are references to ITCTransmission, METC, ITC Midwest, ITC Great Plains and ITC Interconnection together; and
•
“We,” “our” and “us” are references to ITC Holdings together with all of its subsidiaries.
Other definitions
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“Consumers Energy” are references to Consumers Energy Company, a wholly-owned subsidiary of CMS Energy Corporation;
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“DTE Electric” are references to DTE Electric Company, a wholly-owned subsidiary of DTE Energy;
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“DTE Energy” are references to DTE Energy Company;
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“Eiffel” are references to Eiffel Investment Pte Ltd, a private limited company duly organized and validly existing under the laws of Singapore that is the GIC subsidiary that is a minority investor in Investment Holdings and successor to Finn Investment Pte Ltd;
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“FERC” are references to the Federal Energy Regulatory Commission;
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“Fortis” are references to Fortis Inc.;
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“FortisUS” are references to FortisUS Inc., an indirect subsidiary of Fortis;
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“FPA” are references to the Federal Power Act;
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“GIC” are references to GIC Private Limited;
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“ICC” are references to the Illinois Commerce Commission;
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“IP&L” are references to Interstate Power and Light Company, an Alliant Energy Corporation subsidiary;
•
“ISO” are references to Independent System Operators;
•
“Investment Holdings” are references to ITC Investment Holdings Inc., a majority owned indirect subsidiary of Fortis;
•
“IUB” are references to the Iowa Utilities Board;


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•
“KCC” are references to the Kansas Corporation Commission;
•
“kV” are references to kilovolts (one kilovolt equaling 1,000 volts);
•
“kW” are references to kilowatts (one kilowatt equaling 1,000 watts);
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“LIBOR” are references to the London Interbank Offered Rate;
•
“Merger” are references to the merger with Fortis, whereby ITC Holdings merged with Merger Sub and subsequently became a majority owned indirect subsidiary of Fortis;
•
“Merger Agreement” are references to the agreement and plan of merger between Fortis, FortisUS, Merger Sub and ITC Holdings for the Merger;
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“Merger Sub” are references to Element Acquisition Sub, Inc., an indirect subsidiary of Fortis that merged into ITC Holdings in the Merger;
•
“MISO” are references to the Midcontinent Independent System Operator, Inc., a FERC-approved RTO which oversees the operation of the bulk power transmission system for a substantial portion of the Midwestern United States and Manitoba, Canada, and of which ITCTransmission, METC and ITC Midwest are members;
•
“MOPSC” are references to the Missouri Public Service Commission;
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“MPSC” are references to the Michigan Public Service Commission;
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“MPUC” are references to the Minnesota Public Utilities Commission;
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“MVPs” are references to multi-value projects, which have been determined by MISO to have regional value while meeting near-term system needs;
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“MW” are references to megawatts (one megawatt equaling 1,000,000 watts);
•
“NERC” are references to the North American Electric Reliability Corporation;
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“NOLs” are references to net operating loss carryforwards for income taxes;
•
“NYSE” are references to the New York Stock Exchange;
•
“OCC” are references to Oklahoma Corporation Commission;
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“PSCW” are references to the Public Service Commission of Wisconsin;
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“RTO” are references to Regional Transmission Organizations;
•
“Shareholders Agreement” are references to the Shareholders’ Agreement, dated as of October 14, 2016 by and among the Company, Investment Holdings, FortisUS, Finn Investment Pte Ltd, and any other person that becomes a shareholder of Investment Holdings pursuant to such agreement; and
•
“SPP” are references to Southwest Power Pool, Inc., a FERC-approved RTO which oversees the operation of the bulk power transmission system for a substantial portion of the South Central United States, and of which ITC Great Plains is a member.

EXPLANATORY NOTE

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





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PART I
ITEM 1.    BUSINESS.
Overview
Our business consists primarily of the electric transmission operations of our Regulated Operating Subsidiaries. In 2002, ITC Holdings was incorporated in the State of Michigan for the purpose of acquiring ITCTransmission. ITCTransmission was originally formed in 2001 as a subsidiary of DTE Electric, an electric utility subsidiary of DTE Energy, and was acquired in 2003 by ITC Holdings. METC was originally formed in 2001 as a subsidiary of Consumers Energy, an electric and gas utility subsidiary of CMS Energy Corporation, and was acquired in 2006 by ITC Holdings. ITC Midwest was formed in 2007 by ITC Holdings to acquire the transmission assets of IP&L in December 2007. ITC Great Plains was formed in 2006 by ITC Holdings and became a FERC-jurisdictional entity in 2009. ITC Interconnection was formed in 2014 by ITC Holdings and became a FERC-jurisdictional entity in June 2016 after acquiring certain transmission assets from a merchant generating company and placing a newly constructed transmission line in service. We own and operate high-voltage systems in Michigan’s Lower Peninsula and portions of Iowa, Minnesota, Illinois, Missouri, Kansas and Oklahoma that transmit electricity from generating stations to local distribution facilities connected to our systems.
Our business strategy is to own, operate, maintain and invest in transmission infrastructure in order to enhance system integrity and reliability, reduce transmission constraints and support new generating resources to interconnect to our transmission systems. We also are pursuing development projects not within our existing systems, which are also intended to improve overall grid reliability, reduce transmission constraints and facilitate interconnections of new generating resources, as well as enhance competitive wholesale electricity markets.
As electric transmission utilities regulated by the FERC, our Regulated Operating Subsidiaries earn revenues for the use of their electric transmission systems by our customers, which include investor-owned utilities, municipalities, cooperatives, power marketers and alternative energy suppliers. As independent transmission companies, our Regulated Operating Subsidiaries are subject to rate regulation only by the FERC. The rates charged by our Regulated Operating Subsidiaries are established using cost-based formula rates, as discussed in “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cost-Based Formula Rates with True-Up Mechanism.”
The Merger
On February 9, 2016, ITC Holdings entered into the Merger Agreement with Fortis, FortisUS and Merger Sub. On April 20, 2016, Fortis reached a definitive agreement with a subsidiary of GIC for GIC to acquire an indirect 19.9% equity interest in ITC Holdings upon completion of the Merger. On October 14, 2016, ITC Holdings and Fortis completed the Merger contemplated by the Merger Agreement. On the same date, the common shares of ITC Holdings were delisted from the NYSE and the common shares of Fortis were listed and began trading on the NYSE. Fortis continues to have its shares listed on the Toronto Stock Exchange. As a result of the Merger, Merger Sub merged with and into ITC Holdings with ITC Holdings continuing as the surviving corporation and becoming a majority owned indirect subsidiary of Fortis. In the Merger, ITC Holdings shareholders received $22.57 in cash and 0.7520 Fortis common shares for each share of common stock of ITC Holdings. For a discussion of various risks relating to the Merger, see “Item 1A Risk Factors — Risks Relating to the Merger.” Refer to Note 2 to the consolidated financial statements for further details on the Merger.
Development of Business
We are actively developing transmission infrastructure required to meet reliability needs and energy policy objectives. Our long-term growth plan includes continued investment in current transmission systems, generator interconnections and our ongoing development projects. Refer to “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Investment and Operating Results Trends” for additional details about our long-term capital investments. Refer to the discussion of risks associated with our strategic development opportunities in “Item 1A Risk Factors.”
We expect to invest approximately $2.8 billion from 2017 through 2021 at our Regulated Operating Subsidiaries. Included in this amount are capital expenditures to (1) maintain and replace the current transmission infrastructure, (2) enhance system integrity and reliability and accommodate load growth and (3) develop and build regional transmission infrastructure, including additional transmission facilities that will provide interconnection opportunities for generating facilities.


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Development Projects
Through our merchant and international activities, we are actively pursuing projects to upgrade the existing transmission grid and regional transmission facilities, primarily to improve overall grid reliability, reduce transmission constraints, enhance competitive markets and facilitate interconnections of new generating resources, including wind generation and other renewable resources necessary to achieve state and federal policy goals. Additionally, we may pursue other non-traditional transmission investment opportunities not described above.
Segments
We have one reportable segment consisting of our Regulated Operating Subsidiaries. Additionally, we have other subsidiaries focused primarily on business development activities and a holding company whose activities include corporate debt financings and certain other corporate activities. A more detailed discussion of our reportable segment, including financial information about the segment, is included in Note 16 to the consolidated financial statements.
Operations
As transmission-only companies, our Regulated Operating Subsidiaries function as conduits, allowing for power from generators to be transmitted to local distribution systems either entirely through their own systems or in conjunction with neighboring transmission systems. Third parties then transmit power through these local distribution systems to end-use consumers. The transmission of electricity by our Regulated Operating Subsidiaries is a central function to the provision of electricity to residential, commercial and industrial end-use consumers. The operations performed by our Regulated Operating Subsidiaries fall into the following categories:
•
asset planning;
•
engineering, design and construction;
•
maintenance; and
•
real time operations.
Asset Planning
The Asset Planning group uses detailed system models and load forecasts to develop our system expansion capital plans. Expansion capital plans identify projects that would address potential future reliability issues and/or produce economic savings for customers by eliminating constraints.
The Asset Planning group works closely with MISO and SPP in the development of our system expansion capital plans by performing technical evaluations and detailed studies. As the regional planning authorities, MISO and SPP approve regional system improvement plans, which include projects to be constructed by their members, including our MISO Regulated Operating Subsidiaries and ITC Great Plains.
Engineering, Design and Construction
The Engineering, Design and Construction group is responsible for design, equipment specifications, maintenance plans and project engineering for capital, operation and maintenance work. We work with outside contractors to perform various aspects of our engineering, design and construction, but retain internal technical experts who have experience with respect to the key elements of the transmission system such as substations, lines, equipment and protective relaying systems.
Maintenance
We develop and track preventive maintenance plans to promote safe and reliable systems. By performing preventive maintenance on our assets, we can minimize the need for reactive maintenance, resulting in improved reliability. Our Regulated Operating Subsidiaries contract with Utility Lines Construction Services, Inc. (“ULCS”), which is a division of Asplundh Tree Expert Co., to perform the majority of their maintenance. The agreement with ULCS provides us with access to an experienced and scalable workforce with knowledge of our system at an established rate.


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Real Time Operations
System Operations — From our operations facility in Novi, Michigan, transmission system operators continuously monitor the performance of the transmission systems of our Regulated Operating Subsidiaries, using software and communication systems to perform analysis to plan for contingencies and maintain security and reliability following any unplanned events on the system. Transmission system operators are also responsible for the switching and protective tagging function, taking equipment in and out of service to ensure capital construction projects and maintenance programs can be completed safely and reliably.
Local Balancing Authority Operator — Under the functional control of MISO, ITCTransmission and METC operate their electric transmission systems as a combined Local Balancing Authority (“LBA”) area, known as the Michigan Electric Coordinated Systems (“MECS”). From our operations facility in Novi, Michigan, our employees perform the LBA functions as outlined in MISO’s Balancing Authority Agreement. These functions include actual interchange data administration and verification as well as MECS LBA area emergency procedure implementation and coordination. ITC Midwest and ITC Great Plains are not responsible for LBA functions for their respective assets.
Operating Contracts
Our Regulated Operating Subsidiaries have various operating contracts, including numerous interconnection agreements with generation and transmission providers that address terms and conditions of interconnection. The following significant agreements exist at our Regulated Operating Subsidiaries:
ITCTransmission
DTE Electric operates the electric distribution system to which ITCTransmission’s transmission system connects. A set of three operating contracts sets forth the terms and conditions related to DTE Electric’s and ITCTransmission’s ongoing working relationship. These contracts include the following:
Master Operating Agreement. The Master Operating Agreement (the “MOA”), dated as of February 28, 2003, governs the primary day-to-day operational responsibilities of ITCTransmission and DTE Electric and will remain in effect until terminated by mutual agreement of the parties (subject to any required FERC approvals) unless earlier terminated pursuant to its terms. The MOA identifies the control area coordination services that ITCTransmission is obligated to provide to DTE Electric. The MOA also requires DTE Electric to provide certain generation-based support services to ITCTransmission.
Generator Interconnection and Operation Agreement. DTE Electric and ITCTransmission entered into the Generator Interconnection and Operation Agreement (the “GIOA”), dated as of February 28, 2003, in order to establish, re-establish and maintain the direct electricity interconnection of DTE Electric’s electricity generating assets with ITCTransmission’s transmission system for the purposes of transmitting electric power from and to the electricity generating facilities. Unless otherwise terminated by mutual agreement of the parties (subject to any required FERC approvals), the GIOA will remain in effect until DTE Electric elects to terminate the agreement with respect to a particular unit or until a particular unit ceases commercial operation.
Coordination and Interconnection Agreement. The Coordination and Interconnection Agreement (the “CIA”), dated as of February 28, 2003, governs the rights, obligations and responsibilities of ITCTransmission and DTE Electric regarding, among other things, the operation and interconnection of DTE Electric’s distribution system and ITCTransmission’s transmission system, and the construction of new facilities or modification of existing facilities. Additionally, the CIA allocates costs for operation of supervisory, communications and metering equipment. The CIA will remain in effect until terminated by mutual agreement of the parties (subject to any required FERC approvals).
METC
Consumers Energy operates the electric distribution system to which METC’s transmission system connects. METC is a party to a number of operating contracts with Consumers Energy that govern the operations and maintenance of its transmission system. These contracts include the following:
Amended and Restated Easement Agreement. Under the Amended and Restated Easement Agreement (the “Easement Agreement”), dated as of April 29, 2002 and as further supplemented, Consumers Energy provides METC with an easement to the land, which we refer to as premises, on which a majority of METC’s transmission towers, poles, lines and other transmission facilities used to transmit electricity at voltages of at least 120 kV are located, which we refer to collectively as the facilities. Consumers Energy retained for itself


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the rights to, and the value of activities associated with, all other uses of the premises and the facilities covered by the Easement Agreement, such as for distribution of electricity, fiber optics, telecommunications, gas pipelines and agricultural uses. Accordingly, METC is not permitted to use the premises or the facilities covered by the Easement Agreement for any purposes other than to provide electric transmission and related services, to inspect, maintain, repair, replace and remove electric transmission facilities and to alter, improve, relocate and construct additional electric transmission facilities. The easement is further subject to the rights of any third parties that had rights to use or occupy the premises or the facilities prior to April 1, 2001 in a manner not inconsistent with METC’s permitted uses.
METC pays Consumers Energy annual rent of $10 million, in equal quarterly installments, for the easement and related rights under the Easement Agreement. Although METC and Consumers Energy share the use of the premises and the facilities covered by the Easement Agreement, METC pays the entire amount of any rentals, property taxes, inspection fees and other amounts required to be paid to third parties with respect to any use, occupancy, operations or other activities on the premises or the facilities and is generally responsible for the maintenance of the premises and the facilities used for electric transmission at its expense. METC also must maintain commercial general liability insurance protecting METC and Consumers Energy against claims for personal injury, death or property damage occurring on the premises or the facilities and pay for all insurance premiums. METC is also responsible for patrolling the premises and the facilities by air at its expense at least annually and to notify Consumers Energy of any unauthorized uses or encroachments discovered. METC must indemnify Consumers Energy for all liabilities arising from the facilities covered by the Easement Agreement.
METC must notify Consumers Energy before altering, improving, relocating or constructing additional transmission facilities covered by the Easement Agreement. Consumers Energy may respond by notifying METC of reasonable work and design restrictions and precautions that are needed to avoid endangering existing distribution facilities, pipelines or communications lines, in which case METC must comply with these restrictions and precautions. METC has the right at its own expense to require Consumers Energy to remove and relocate these facilities, but Consumers Energy may require payment in advance or the provision of reasonable security for payment by METC prior to removing or relocating these facilities, and Consumers Energy need not commence any relocation work until an alternative right-of-way satisfactory to Consumers Energy is obtained at METC’s expense.
The term of the Easement Agreement runs through December 31, 2050 and is subject to 10 automatic 50-year renewals after that time unless METC provides one year’s notice of its election not to renew the term. Consumers Energy may terminate the Easement Agreement 30 days after giving notice of a failure by METC to pay its quarterly installment if METC does not cure the non-payment within the 30-day notice period. At the end of the term or upon any earlier termination of the Easement Agreement, the easement and related rights terminate and the transmission facilities revert to Consumers Energy.
Amended and Restated Operating Agreement. Under the Amended and Restated Operating Agreement (the “Operating Agreement”), dated as of April 29, 2002, METC agrees to operate its transmission system to provide all transmission customers with safe, efficient, reliable and nondiscriminatory transmission service pursuant to its tariff. Among other things, METC is responsible under the Operating Agreement for maintaining and operating its transmission system, providing Consumers Energy with information and access to its transmission system and related books and records, administering and performing the duties of control area operator (that is, the entity exercising operational control over the transmission system) and, if requested by Consumers Energy, building connection facilities necessary to permit interaction with new distribution facilities built by Consumers Energy. Consumers Energy has corresponding obligations to provide METC with access to its books and records and to build distribution facilities necessary to provide adequate and reliable transmission services to wholesale customers. Consumers Energy must cooperate with METC as METC performs its duties as control area operator, including by providing reactive supply and voltage control from generation sources or other ancillary services and reducing load. The Operating Agreement is effective through 2050 and is subject to 10 automatic 50-year renewals after that time, unless METC provides one year’s notice of its election not to renew.
Amended and Restated Purchase and Sale Agreement for Ancillary Services. The Amended and Restated Purchase and Sale Agreement for Ancillary Services (the “Ancillary Services Agreement”) is dated as of April 29, 2002. Since METC does not own any generating facilities, it must procure ancillary services from third party suppliers, such as Consumers Energy. Currently, under the Ancillary Services Agreement, METC pays


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Consumers Energy for providing certain generation based services necessary to support the reliable operation of the bulk power grid, such as voltage support and generation capability and capacity to balance loads and generation. METC is not precluded from procuring these ancillary services from third party suppliers when available. The Ancillary Services Agreement is subject to rolling one-year renewals starting May 1, 2003, unless terminated by either METC or Consumers Energy with six months prior written notice.
Amended and Restated Distribution-Transmission Interconnection Agreement. The Amended and Restated Distribution-Transmission Interconnection Agreement (the “DT Interconnection Agreement”), dated April 1, 2001 and most recently amended and restated effective as of January 1, 2015, provides for the interconnection of Consumers Energy’s distribution system with METC’s transmission system and defines the continuing rights, responsibilities and obligations of the parties with respect to the use of certain of their own and the other party’s properties, assets and facilities. METC agrees to provide Consumers Energy interconnection service at agreed-upon interconnection points, and the parties have mutual responsibility for maintaining voltage and compensating for reactive power losses resulting from their respective services. The DT Interconnection Agreement is effective so long as any interconnection point is connected to METC, unless it is terminated earlier by mutual agreement of METC and Consumers Energy.
Amended and Restated Generator Interconnection Agreement. The Amended and Restated Generator Interconnection Agreement (the “Generator Interconnection Agreement”), dated as of April 29, 2002 and most recently amended effective as of October 1, 2016, specifies the terms and conditions under which Consumers Energy and METC maintain the interconnection of Consumers Energy’s generation resources and METC’s transmission assets. The Generator Interconnection Agreement is effective either until it is replaced by any MISO-required contract, or until mutually agreed by METC and Consumers Energy to terminate, but not later than the date that all listed generators cease commercial operation.
ITC Midwest
IP&L operates the electric distribution system to which ITC Midwest’s transmission system connects. ITC Midwest is a party to a number of operating contracts with IP&L that govern the operations and maintenance of its transmission system. These contracts include the following:
Distribution-Transmission Interconnection Agreement. The Distribution-Transmission Interconnection Agreement (the “DTIA”), dated as of December 17, 2007 and amended and restated effective as of December 1, 2016, governs the rights, responsibilities and obligations of ITC Midwest and IP&L, with respect to the use of certain of their own and the other parties’ property, assets and facilities and the construction of new facilities or modification of existing facilities. Additionally, the DTIA sets forth the terms pursuant to which the equipment and facilities and the interconnection equipment of IP&L will continue to connect ITC Midwest’s facilities through which ITC Midwest provides transmission service under the MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff. The DTIA will remain in effect until terminated by mutual agreement by the parties (subject to any required FERC approvals) or as long as any interconnection point of IP&L is connected to ITC Midwest’s facilities, unless modified by written agreement of the parties.
Large Generator Interconnection Agreement. ITC Midwest, IP&L and MISO entered into the Large Generator Interconnection Agreement (the “LGIA”), dated as of December 20, 2007 and amended as of August 6, 2013, in order to establish, re-establish and maintain the direct electricity interconnection of IP&L’s electricity generating assets with ITC Midwest’s transmission system for the purposes of transmitting electric power from and to the electricity generating facilities. The LGIA will remain in effect until terminated by ITC Midwest or until IP&L elects to terminate the agreement if a particular unit ceases commercial operation for three consecutive years.
Operations Services Agreement For 34.5 kV Transmission Facilities. ITC Midwest and IP&L entered into the Operations Services Agreement for 34.5 kV Transmission Facilities (the “OSA”), effective as of January 1, 2011, under which IP&L performs certain operations functions for ITC Midwest’s 34.5 kV transmission system on behalf of ITC Midwest. The OSA provides that when ITC Midwest upgrades 34.5 kV facilities to higher operating voltages it may notify IP&L of the change and the OSA is no longer applicable to those facilities. The OSA will remain in full force and effect until December 31, 2015 and will extend automatically from year to year thereafter until terminated by either party upon not less than one year prior written notice to the other party.


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ITC Great Plains
Amended and Restated Maintenance Agreement. Mid-Kansas Electric Company LLC (“Mid-Kansas”) and ITC Great Plains have entered into a Maintenance Agreement (the “Mid-Kansas Agreement”), dated as of August 24, 2010, and most recently amended effective as of June 1, 2015, pursuant to which Mid-Kansas has agreed to perform various field operations and maintenance services related to certain ITC Great Plains facilities. The Mid-Kansas Agreement has an initial term of 10 years and automatic 10-year renewals unless terminated (1) due to a breach by the non-terminating party following notice and failure to cure, (2) by mutual consent of the parties, or (3) by ITC Great Plains under certain limited circumstances. Services must continue to be provided for at least six months subsequent to the termination date in any case.
Regulatory Environment
Many regulators and public policy makers support the need for further investment in the transmission grid. The growth and changing mix of electricity generation, wholesale power sales and consumption combined with historically inadequate transmission investment have resulted in significant transmission constraints across the United States and increased stress on aging equipment. These problems will continue without increased investment in transmission infrastructure. Transmission system investments can also increase system reliability and reduce the frequency of power outages. Such investments can reduce transmission constraints and improve access to lower cost generation resources, resulting in a lower overall cost of delivered electricity for end-use consumers. After the 2003 blackout that affected sections of the Northeastern and Midwestern United States and Ontario, Canada, the Department of Energy (the “DOE”) established the Office of Electric Transmission and Distribution (now the Office of Electricity Delivery and Energy Reliability), focused on working with reliability experts from the power industry, state governments and their Canadian counterparts to improve grid reliability and increase investment in the country’s electric infrastructure. In addition, the FERC has signaled its desire for substantial new investment in the transmission sector by implementing various financial and other incentives.
The FERC has also issued orders to promote non-discriminatory transmission access for all transmission customers. In the United States, electric transmission assets are predominantly owned, operated and maintained by utilities that also own electricity generation and distribution assets, known as vertically integrated utilities. The FERC has recognized that the vertically-integrated utility model inhibits the provision of non-discriminatory transmission access and, in order to alleviate this potential discrimination, the FERC has mandated that all transmission systems over which it has jurisdiction must be operated in a comparable, non-discriminatory manner such that any seller of electricity affiliated with a transmission owner (“TO”) or operator is not provided with preferential treatment. The FERC has also indicated that independent transmission companies can play a prominent role in furthering its policy goals and has encouraged the legal and functional separation of transmission operations from generation and distribution operations.
The FERC requires compliance with certain reliability standards by transmission owners and may take enforcement actions for violations, including the imposition of substantial fines. NERC is responsible for developing and enforcing these mandatory reliability standards. We continually assess our transmission systems against standards established by NERC, as well as the standards of applicable regional entities under NERC that have been delegated certain authority for the purpose of proposing and enforcing reliability standards. Finally, utility holding companies are subject to FERC regulations related to access to books and records in addition to the requirement of the FERC to review and approve mergers and consolidations involving utility assets and holding companies in certain circumstances.
Federal Regulation
As electric transmission companies, our Regulated Operating Subsidiaries are regulated by the FERC. The FERC is an independent regulatory commission within the DOE that regulates the interstate transmission and certain wholesale sales of natural gas, the transmission of oil and oil products by pipeline and the transmission and wholesale sales of electricity in interstate commerce. The FERC also administers accounting and financial reporting regulations and standards of conduct for the companies it regulates. In 1996, in order to facilitate open access transmission for participants in wholesale power markets, the FERC issued Order No. 888. The open access policy promulgated by the FERC in Order No. 888 was upheld in a United States Supreme Court decision, State of New York vs. FERC, issued on March 4, 2002. To facilitate open access, among other things, FERC Order No. 888 encouraged investor owned utilities to cede operational control over their transmission systems to ISOs, which are not-for-profit entities.


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As an alternative to ceding operating control of their transmission assets to ISOs, certain investor owned utilities began to promote the formation of for-profit transmission companies, which would assume control of the operation of the grid. In December 1999, the FERC issued Order No. 2000, which strongly encouraged utilities to voluntarily transfer operational control of their transmission systems to RTOs. RTOs, as envisioned in Order No. 2000, would assume many of the functions of an ISO, but the FERC permitted greater flexibility with regard to the organization and structure of RTOs than it had for ISOs. RTOs could accommodate the inclusion of independently owned, for-profit companies that own transmission assets within their operating structure. Independent ownership would facilitate not only the independent operation of the transmission systems, but also the formation of companies with a greater financial interest in maintaining and augmenting the capacity and reliability of those systems. RTOs such as MISO and SPP monitor electric reliability and are responsible for coordinating the operation of the wholesale electric transmission system and ensuring fair, non-discriminatory access to the transmission grid.
FERC Order No. 1000 (“Order 1000”) amends certain existing transmission planning and cost allocation requirements to ensure that FERC-jurisdictional services are provided at just and reasonable rates and on a basis that is just and reasonable and not unduly discriminatory or preferential. With respect to transmission planning, Order 1000: (1) requires that each public utility transmission provider participate in a regional transmission planning process that produces a regional transmission plan; (2) requires that each public utility transmission provider amend its Open Access Transmission Tariff to describe procedures that provide for the consideration of transmission needs driven by public policy requirements in the local and regional transmission planning processes; (3) removes a federal right of first refusal for certain new transmission facilities from FERC-approved tariffs and agreements; and (4) improves coordination between neighboring transmission planning regions for new interregional transmission facilities. MISO and SPP are compliant with the regional and interregional requirements of Order 1000 after making multiple compliance filings at the FERC.
Order 1000 could potentially lead to greater competition for certain future transmission projects, including within our current operating areas. We are currently exploring opportunities resulting from Order 1000 within MISO and SPP as well as other RTOs.
Revenue Requirement Calculations and Cost Sharing for Projects with Regional Benefits
The cost-based formula rates used by our Regulated Operating Subsidiaries include revenue requirement calculations for various types of projects. Network revenues continue to be the largest component of revenues recovered through our formula rates. However, regional cost sharing revenues are growing as a result of projects that have been identified by MISO or SPP as having regional benefits, and therefore eligible for regional cost recovery under their tariffs. Separate calculations of revenue requirement are performed for projects that have been approved for regional cost sharing and impact only which parties ultimately pay for the transmission services related to these projects and do not impact our financial results.
We have projects that are eligible for regional cost sharing under the MISO tariff, such as certain network upgrade projects, and the MVPs, including the four North Central MVPs and the Thumb Loop Project in Michigan. Additionally, certain projects at ITC Great Plains are eligible for recovery through a region-wide charge in the SPP tariff, including two regional cost sharing projects in Kansas. Certain of these projects are described in more detail in “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Recent Developments.”
State Regulation
The regulatory agencies in the states where our Regulated Operating Subsidiaries’ assets are located do not have jurisdiction over our rates or terms and conditions of service. However, they typically have jurisdiction over siting of transmission facilities and related matters as described below. Additionally, we are subject to the regulatory oversight of various state environmental quality departments for compliance with any state environmental standards and regulations.
ITCTransmission, METC and ITC Interconnection
Michigan
The MPSC has jurisdiction over the siting of certain transmission facilities. Additionally, ITCTransmission, METC and ITC Interconnection have the right as independent transmission companies to condemn property in the state of Michigan for the purposes of building or maintaining transmission facilities.


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ITCTransmission, METC and ITC Interconnection are also subject to the regulatory oversight of the Michigan Department of Environmental Quality, the Michigan Department of Natural Resources and certain local authorities for compliance with all environmental standards and regulations.
ITC Midwest
Iowa
The IUB has the power of supervision over the construction, operation and maintenance of transmission facilities in Iowa by any entity, which includes the power to issue franchises. Iowa law further provides that any entity granted a franchise by the IUB is vested with the power of condemnation in Iowa to the extent the IUB approves and deems necessary for public use. A city has the power, pursuant to Iowa law, to grant a franchise to erect, maintain and operate transmission facilities within the city, which franchise may regulate the conditions required and manner of use of the streets and public grounds of the city and may confer the power to appropriate and condemn private property.
ITC Midwest also is subject to the regulatory oversight of certain state agencies (including the Iowa Department of Natural Resources) and certain local authorities with respect to the issuance of environmental, highway, railroad and similar permits.
Minnesota
The MPUC has jurisdiction over the construction, siting and routing of new transmission lines or upgrades of existing lines through Minnesota’s Certificate of Need and Route Permit Processes. Transmission companies are also required to participate in the State’s Biennial Transmission Planning Process and are subject to the state’s preventative maintenance requirements. Pursuant to Minnesota law, ITC Midwest has the right as an independent transmission company to condemn property in the State of Minnesota for the purpose of building new transmission facilities.
ITC Midwest is also subject to the regulatory oversight of the Minnesota Pollution Control Agency, the Minnesota Department of Natural Resources, the MPUC in conjunction with the Department of Commerce and certain local authorities for compliance with applicable environmental standards and regulations.
Illinois
The ICC exercises jurisdiction over siting of new transmission lines through its requirements for Certificates of Public Convenience and Necessity and Right-Of-Way acquisition that apply to construction of new or upgraded facilities.
ITC Midwest also is subject to the regulatory oversight of the Illinois Environmental Protection Agency, the Illinois Department of Natural Resources, the Illinois Pollution Control Board and certain local authorities for compliance with all environmental standards and regulations.
Missouri
Because ITC Midwest is a “public utility” and an “electrical corporation” under Missouri law, the MOPSC has jurisdiction to determine whether ITC Midwest may operate in such capacity. The MOPSC also exercises jurisdiction with regard to other non-rate matters affecting this Missouri asset such as transmission substation construction, general safety and the transfer of the franchise or property.
ITC Midwest is also subject to the regulatory oversight of the Missouri Department of Natural Resources for compliance with all environmental standards and regulations relating to this transmission line.
Wisconsin
ITC Midwest is a “public utility” and independent transmission owner in Wisconsin. The PSCW in a May 2014 order granted ITC Midwest a certificate of authority to transact public utility business in the state. In a separate May 2014 order, the PSCW also recognized ITC Holdings Corp. as a public utility holding company under Wisconsin statutes.
The PSCW exercises jurisdiction over the siting of new transmission lines through the issuance of certificates of authority and certificates of public convenience and necessity. Upon receipt of such certificates for a transmission project, ITC Midwest has condemnation authority as a foreign transmission provider under Wisconsin law. ITC


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Midwest is also subject to the jurisdiction of certain local and state agencies, including the Wisconsin Department of Natural Resources, relating to environmental and road permits.
ITC Great Plains
Kansas
ITC Great Plains is a “public utility” in Kansas and an “electric utility” pursuant to state statutes. The KCC issued an order approving the issuance of a limited certificate of convenience to ITC Great Plains for the purposes of building, owning and operating SPP transmission projects in Kansas. In addition to its certificate of authority, the KCC has jurisdiction over the siting of electric transmission lines.
ITC Great Plains is also subject to the regulatory oversight of the Kansas Department of Health and Environment for compliance with all environmental standards and regulations relating to the construction phase of any transmission line.
Oklahoma
ITC Great Plains has approval from the OCC to operate in Oklahoma, pursuant to Oklahoma Statutes as an electric public utility providing only transmission services. The OCC does not exercise jurisdiction over the siting of any transmission lines.
ITC Great Plains may be subject to the regulatory oversight of Oklahoma Department of Environmental Quality for compliance with environmental standards and regulations relating to construction of proposed transmission lines.
Sources of Revenue
See “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations — Operating Revenues” for a discussion of our principal sources of revenue.
Seasonality
The cost-based formula rates in effect for our Regulated Operating Subsidiaries, as discussed in “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cost-Based Formula Rates with True-Up Mechanism,” mitigate the seasonality of net income for our Regulated Operating Subsidiaries. Our Regulated Operating Subsidiaries accrue or defer revenues to the extent that the actual revenue requirement for the reporting period is higher or lower, respectively, than the amounts billed relating to that reporting period. For example, to the extent that amounts billed are less than our revenue requirement for a reporting period, a revenue accrual is recorded for the difference and the difference results in no net income impact.
Operating cash flows are seasonal at our MISO Regulated Operating Subsidiaries, in that cash received for revenues is typically higher in the summer months when peak load is higher.
Principal Customers
Our principal transmission service customers are DTE Electric, Consumers Energy and IP&L, which accounted for approximately 20.7%, 21.7% and 25.5%, respectively, of our consolidated billed revenues for the year ended December 31, 2016. One or more of these customers together have consistently represented a significant percentage of our operating revenue. These percentages of total billed revenues of DTE Electric, Consumers Energy and IP&L include the collection of 2014 revenue accruals and deferrals and exclude any amounts for the 2016 revenue accruals and deferrals that were included in our 2016 operating revenues, but will not be billed to our customers until 2018. Refer to “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cost-Based Formula Rates with True-Up Mechanism” for a discussion on the difference between billed revenues and operating revenues. Our remaining revenues were generated from providing service to other entities such as alternative electricity suppliers, power marketers and other wholesale customers that provide electricity to end-use consumers and from transaction-based capacity reservations. Nearly all of our revenues are from transmission customers in the United States. Although we may recognize allocated revenues from time to time from Canadian entities reserving transmission over the Ontario or Manitoba interface, these revenues have not been and are not expected to be material to us.


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Billing
MISO and SPP are responsible for billing and collecting the majority of our transmission service revenues as well as independently administering the transmission tariff in their respective service territory. As the billing agents for our MISO Regulated Operating Subsidiaries and ITC Great Plains, MISO and SPP independently bill DTE Electric, Consumers Energy, IP&L and other customers on a monthly basis and collect fees for the use of our transmission systems.
See “Item 7A Quantitative and Qualitative Disclosures about Market Risk — Credit Risk” for discussion of our credit policies.
Competition
Each of our MISO Regulated Operating Subsidiaries operates the primary transmission system in its respective service area and has limited competition for certain projects. However, the competitive environment is evolving due to the implementation of Order 1000. See further discussion of Order 1000 above under “Regulatory Environment — Federal Regulation.” For our subsidiaries focused on development opportunities for transmission investment in other service areas, the incumbent utilities or other entities with transmission development initiatives may compete with us by seeking approval to be named the party authorized to build new capital projects that we are also pursuing. Because our Regulated Operating Subsidiaries are currently the only transmission companies that are independent from electricity market participants, we believe that we are best able to develop these projects in a non-discriminatory manner. However, there are no assurances that we will be selected to develop projects other entities are also pursuing.
Employees
As of December 31, 2016, we had 660 employees. We consider our relations with our employees to be good.
Environmental Matters
We are subject to federal, state and local environmental laws and regulations, which impose limitations on the discharge of pollutants into the environment, establish standards for the management, treatment, storage, transportation and disposal of solid and hazardous wastes and hazardous materials, and impose obligations to investigate and remediate contamination in certain circumstances. Liabilities relating to investigation and remediation of contamination, as well as other liabilities concerning hazardous materials or contamination, such as claims for personal injury or property damage, may arise at many locations, including formerly owned or operated properties and sites where wastes have been treated or disposed of, as well as properties currently owned or operated by us. Such liabilities may arise even where the contamination does not result from noncompliance with applicable environmental laws. Under some environmental laws, such liabilities may also be joint and several, meaning that a party can be held responsible for more than its share of the liability involved, or even the entire share. Although environmental requirements generally have become more stringent and compliance with those requirements more expensive, we are not aware of any specific developments that would increase our costs for such compliance in a manner that would be expected to have a material adverse effect on our results of operations, financial position or liquidity.
Our assets and operations also involve the use of materials classified as hazardous, toxic or otherwise dangerous. Many of the properties that we own or operate have been used for many years, and include older facilities and equipment that may be more likely than newer ones to contain or be made from such materials. Some of these properties include aboveground or underground storage tanks and associated piping. Some of them also include large electrical equipment filled with mineral oil, which may contain or previously have contained polychlorinated biphenyls, or PCBs. Our facilities and equipment are often situated on or near property owned by others so that, if they are the source of contamination, others’ property may be affected. For example, aboveground and underground transmission lines sometimes traverse properties that we do not own and transmission assets that we own or operate are sometimes commingled at our transmission stations with distribution assets owned or operated by our transmission customers.
Some properties in which we have an ownership interest or at which we operate are, or are suspected of being, affected by environmental contamination. We are not aware of any pending or threatened claims against us with respect to environmental contamination relating to these properties, or of any investigation or remediation of contamination at these properties, that entail costs likely to materially affect us. Some facilities and properties are located near environmentally sensitive areas such as wetlands.


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Claims have been made or threatened against electric utilities for bodily injury, disease or other damages allegedly related to exposure to electromagnetic fields associated with electric transmission and distribution lines. While we do not believe that a causal link between electromagnetic field exposure and injury has been generally established and accepted in the scientific community, the liabilities and costs imposed on our business could be significant if such a relationship is established or accepted. We are not aware of any pending or threatened claims against us for bodily injury, disease or other damages allegedly related to exposure to electromagnetic fields and electric transmission and distribution lines that entail costs likely to have a material adverse effect on our results of operations, financial position or liquidity.
Filings Under the Securities Exchange Act of 1934
Our internet address is http://www.itc-holdings.com. All of our reports filed pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), including our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports, can be accessed free of charge through our website. These reports are available as soon as practicable after they are electronically filed with the Securities and Exchange Commission (the “SEC”). Our website also has posted our Code of Conduct and Ethics. The information on our website is not incorporated by reference into this report.
To learn more about us, please visit our website at http://www.itc-holdings.com. We use our website as a channel of distribution of material company information. Financial and other material information regarding us is routinely posted on our website and is readily accessible.
The public may also read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington DC, 20549. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC also maintains a website that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC. The internet address is http://www.sec.gov.
ITEM 1A.     RISK FACTORS.
Risks Related to Our Business
Certain elements of our Regulated Operating Subsidiaries’ formula rates can be and have been challenged, which could result in lowered rates and/or refunds of amounts previously collected and thus have an adverse effect on our business, financial condition, results of operations and cash flows.
Our Regulated Operating Subsidiaries provide transmission service under rates regulated by the FERC. The FERC has approved the cost-based formula rates used by our Regulated Operating Subsidiaries to calculate their respective annual revenue requirements, but it has not expressly approved the amount of actual capital and operating expenditures to be used in the formula rates. All aspects of our Regulated Operating Subsidiaries’ rates approved by the FERC, including the formula rate templates, the rates of return on the actual equity portion of their respective capital structures and the approved targeted capital structures, are subject to challenge by interested parties at the FERC, or by the FERC on its own initiative in a proceeding under Section 206 of the FPA. In addition, interested parties may challenge the annual implementation and calculation by our Regulated Operating Subsidiaries of their projected rates and formula rate true up pursuant to their approved formula rates under the Regulated Operating Subsidiaries' formula rate implementation protocols. End-use consumers and entities supplying electricity to end-use consumers may also attempt to influence government and/or regulators to change the rate setting methodologies that apply to our Regulated Operating Subsidiaries, particularly if rates for delivered electricity increase substantially. If a challenger can establish that any of these aspects are unjust, unreasonable, unduly discriminatory or preferential, then the FERC will make appropriate prospective adjustments to them and/or disallow any of our Regulated Operating Subsidiaries’ inclusion of those aspects in the rate setting formula. This could result in lowered rates and/or refunds of amounts collected, any of which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
In November 2013, certain parties filed a joint complaint with the FERC under Section 206 of the FPA, requesting that the FERC find the base rate of return on equity for all MISO transmission owners, including ITCTransmission, METC and ITC Midwest, to be unjust and unreasonable. The joint complainants sought a FERC order reducing the base rate of return on equity used in the MISO transmission owners’ formula transmission rate, reducing the targeted equity component of MISO transmission owners’ capital structures and terminating the return on equity adders approved for ITCTransmission and METC. Although the FERC issued an order rejecting the November


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2013 complaint as to the capital structures and ITCTransmission's and METC’s equity adders, a hearing was ordered on the November 2013 complaint's allegations as to the base rate of return on equity for all MISO transmission owners. On December 22, 2015, the presiding administrative law judge issued an initial decision recommending to the FERC a reduction in the base rate of return on equity of the MISO Transmission owners from 12.38% to 10.32%, with a maximum rate of 11.35%. On September 28, 2016, the FERC issued an order affirming the presiding administrative law judge's initial decision, with the new rates to become effective immediately and for the period from November 12, 2013 through February 11, 2015.
In February 2015, an additional complaint was filed under Section 206 of the FPA seeking a FERC order reducing the base rate of return on equity for all MISO transmission owners, including for our MISO Regulated Operating Subsidiaries, to 8.67%. On June 30, 2016, the presiding administrative law judge issued an initial decision on the February 2015 complaint, which recommended a base rate of return on equity of 9.70%, which would be applicable for the period from February 12, 2015 through May 11, 2016 and going forward from the date on which the FERC issues an order on the February 2015 complaint, with a maximum rate of 10.68%. In resolving the February 2015 complaint, we expect the FERC to establish a new base rate and zone of reasonable returns that will be used, along with any incentive adders, to calculate the refund liability for the period from February 12, 2015 through May 11, 2016 and going forward from the date on which the FERC issues an order. A decision from the FERC on the February 2015 complaint is anticipated in 2017. In 2016, 2015 and 2014, we adjusted revenues downward to accrue for the refund liability based on our estimate of the outcome of these complaints, which had a negative effect on our net income for those periods. The resolution of the second complaint may reduce our future revenues and net income and have an adverse effect on our future results of operations, cash flows and financial condition.
Our actual capital investment may be lower than planned, which would cause a lower than anticipated rate base and would therefore result in lower revenues, earnings and associated cash flows compared to our current expectations. In addition, we expect to invest in strategic development opportunities to improve the efficiency and reliability of the transmission grid, but we cannot provide assurance that we will be able to initiate or complete any of these investments. In addition, we expect to incur expenses related to the pursuit of development opportunities, which may be higher than forecasted.
Each of our operating subsidiaries’ rate base, revenues, earnings and associated cash flows are determined in part by additions to property, plant and equipment and when those additions are placed in service. We anticipate making significant capital investments over the next several years; however, the amounts could change significantly due to factors beyond our control. If our operating subsidiaries’ capital investment and the resulting in-service property, plant and equipment are lower than anticipated for any reason, our operating subsidiaries will have a lower than anticipated rate base, thus causing their revenue requirements and future earnings to be lower than anticipated.
We are pursuing broader strategic development investment opportunities including those related to building regional transmission facilities and interconnections for generating resources, among others. Incumbent utilities or other transmission development entities may compete with us for regulatory approval to develop capital projects that we are pursuing. If we are unable to compete successfully for approval of these projects, our opportunities to expand our rate base and increase our revenues and earnings may become limited.
Any capital investment at our operating subsidiaries or as a result of our broader strategic development initiatives may be lower than our published estimates due to, among other factors, the impact of actual loads, forecasted loads, regional economic conditions, weather conditions, union strikes, labor shortages, material and equipment prices and availability, our ability to obtain financing for such expenditures, if necessary, limitations on the amount of construction that can be undertaken on our system or transmission systems owned by others at any one time, regulatory requirements relating to our rate construct, environmental issues, siting, regional planning, cost recovery or other issues, or as a result of legal proceedings and variances between estimated and actual costs of construction contracts awarded and the potential for greater competition. Our ability to engage in construction projects resulting from pursuing these initiatives is subject to significant uncertainties, including the factors discussed above, and will depend on obtaining any necessary regulatory and other approvals for the project and for us to initiate construction, our achieving status as the builder of the project in some circumstances and other factors. Therefore, we can provide no assurance as to the actual level of investment we may achieve at our operating subsidiaries or as a result of the broader strategic development initiatives.


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In addition, we expect to incur expenses to pursue strategic development investment opportunities. If these expenses are higher than anticipated, our future results of operations, cash flows and financial condition could be materially and adversely affected.
The regulations to which we are subject may limit our ability to raise capital and/or pursue acquisitions, development opportunities or other transactions or may subject us to liabilities.
Each of our Regulated Operating Subsidiaries is a “public utility” under the FPA and, accordingly, is subject to regulation by the FERC. Approval of the FERC is required under Section 203 of the FPA for a disposition or acquisition of regulated public utility facilities, either directly or indirectly through a holding company. Such approval is also required to acquire a significant interest in securities of a public utility. Section 203 of the FPA also provides the FERC with explicit authority over utility holding companies’ purchases or acquisitions of, and mergers or consolidations with, a public utility. Finally, each of our Regulated Operating Subsidiaries must also seek approval by the FERC under Section 204 of the FPA for issuances of its securities (including debt securities).
We are also pursuing development projects for construction of transmission facilities and interconnections with generating resources. These projects may require regulatory approval by Federal agencies, including the FERC, applicable RTOs and state and local regulatory agencies. Failure to secure such regulatory approval for new strategic development projects could adversely affect our ability to grow our business and increase our revenues. If we fail to obtain these approvals when necessary, we may incur liabilities for such failure.
Changes in energy laws, regulations or policies could impact our business, financial condition, results of operations and cash flows.
Each of our Regulated Operating Subsidiaries is regulated by the FERC as a “public utility” under the FPA and is a transmission owner in MISO or SPP. We cannot predict whether the approved rate methodologies for any of our Regulated Operating Subsidiaries will be changed. In addition, the U.S. Congress periodically considers enacting energy legislation that could assign new responsibilities to the FERC, modify provisions of the FPA or provide the FERC or another entity with increased authority to regulate transmission matters. We cannot predict whether, and to what extent, our Regulated Operating Subsidiaries may be affected by any such changes in federal energy laws, regulations or policies in the future. While our Regulated Operating Subsidiaries are subject to the FERC’s exclusive jurisdiction for purposes of rate regulation, changes in state laws affecting other matters, such as transmission siting and construction, could limit investment opportunities available to us.
If amounts billed for transmission service for our Regulated Operating Subsidiaries’ transmission systems are lower than expected, or our actual revenue requirements are higher than expected, the timing of actual collection of our total revenues would be delayed.
If amounts billed for transmission service are lower than expected, which could result from lower network load or point-to-point transmission service on our Regulated Operating Subsidiaries’ transmission systems due to a weak economy, changes in the nature or composition of the transmission assets of our Regulated Operating Subsidiaries and surrounding areas, poor transmission quality of neighboring transmission systems, or for any other reason, the timing of actual collection of our total revenue requirement would likely be delayed until such circumstances are adjusted through the true-up mechanism in our Regulated Operating Subsidiaries’ formula rates. In addition, if the revenue requirements of our Regulated Operating Subsidiaries are higher than expected, due to higher actual expenditures compared to the forecasted expenditures used to develop their billing rates or for any other reason, the timing of actual collection of our Regulated Operating Subsidiaries' total revenue requirements would likely be delayed until such circumstances are reflected through the true-up mechanism in our Regulated Operating Subsidiaries' expected, formula rates. The effect of such under-collection would be to reduce the amount of our available cash resources from what we had expected, until such under-collection is corrected through the true-up mechanism in the formula rate template, which may require us to increase our outstanding indebtedness, thereby reducing our available borrowing capacity, and may require us to pay interest at a rate that exceeds the interest to which we are entitled in connection with the operation of the true-up mechanism.


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Each of our MISO Regulated Operating Subsidiaries depends on its primary customer for a substantial portion of its revenues, and any material failure by those primary customers to make payments for transmission services could have a material adverse effect on our business, financial condition, results of operations and cash flows.
ITCTransmission derives a substantial portion of its revenues from the transmission of electricity to DTE Electric’s local distribution facilities. DTE Electric accounted for approximately 57.3% of ITCTransmission’s total billed revenues for the year ended December 31, 2016 and is expected to constitute the majority of ITCTransmission’s revenues for the foreseeable future. DTE Electric is rated BBB+/stable and A2/stable by Standard and Poor’s Ratings Services and Moody’s Investors Services, Inc., respectively. Similarly, Consumers Energy accounted for approximately 76.7% of METC’s total billed revenues for the year ended December 31, 2016 and is expected to constitute the majority of METC’s revenues for the foreseeable future. Consumers Energy is rated BBB+/stable and A3/stable by Standard and Poor’s Ratings Services and Moody’s Investors Services, Inc., respectively. Further, IP&L accounted for approximately 73.3% of ITC Midwest’s total billed revenues for the year ended December 31, 2016 and is expected to constitute the majority of ITC Midwest’s revenues for the foreseeable future. IP&L is rated A-/stable and Baa1/stable by Standard and Poor’s Ratings Services and Moody’s Investors Services, Inc., respectively. These percentages of total billed revenues of DTE Electric, Consumers Energy and IP&L include the collection of 2014 revenue accruals and deferrals and exclude any amounts for the 2016 revenue accruals and deferrals that were included in our 2016 operating revenues, but will not be billed to our customers until 2018.
Any material failure by DTE Electric, Consumers Energy or IP&L to make payments for transmission services could have an adverse effect on our business, financial condition, results of operations and cash flows.
A significant amount of the land on which our assets are located is subject to easements, mineral rights and other similar encumbrances. As a result, we must comply with the provisions of various easements, mineral rights and other similar encumbrances, which may adversely impact their ability to complete construction projects in a timely manner.
METC does not own the majority of the land on which its electric transmission assets are located. Instead, under the provisions of an Easement Agreement with Consumers Energy, METC pays annual rent of $10 million to Consumers Energy in exchange for rights-of-way, leases, fee interests and licenses which allow METC to use the land on which its transmission lines are located. Under the terms of the Easement Agreement, METC’s easement rights could be eliminated if METC fails to meet certain requirements, such as paying contractual rent to Consumers Energy in a timely manner. Additionally, a significant amount of the land on which our other subsidiaries’ assets are located is subject to easements, mineral rights and other similar encumbrances. As a result, they must comply with the provisions of various easements, mineral rights and other similar encumbrances, which may adversely impact their ability to complete their construction projects in a timely manner.
We contract with third parties to provide services for certain aspects of our business. If any of these agreements are terminated, we may face a shortage of labor or replacement contractors to provide the services formerly provided by these third parties.
We enter into various agreements and arrangements with third parties to provide services for construction, maintenance and operations of certain aspects of our business, which, if terminated, could result in a shortage of a readily available workforce to provide these services. If any of these agreements or arrangements is terminated for any reason, we may face difficulty finding a qualified replacement work force to provide such services, which could have an adverse effect on our ability to carry on our business and on our results of operations.
Hazards associated with high-voltage electricity transmission may result in suspension of our operations or the imposition of civil or criminal penalties.
Our operations are subject to the usual hazards associated with high-voltage electricity transmission, including explosions, fires, inclement weather, natural disasters, mechanical failure, unscheduled downtime, equipment interruptions, remediation, chemical spills, discharges or releases of toxic or hazardous substances or gases and other environmental risks. The hazards can cause personal injury and loss of life, severe damage to or destruction of property and equipment and environmental damage, and may result in suspension of operations and the imposition of civil or criminal penalties. We maintain property and casualty insurance, but we are not fully insured against all potential hazards incident to our business, such as damage to poles, towers and lines or losses caused by outages.


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We are subject to environmental regulations and to laws that can give rise to substantial liabilities from environmental contamination.
We are subject to federal, state and local environmental laws and regulations, which impose limitations on the discharge of pollutants into the environment, establish standards for the management, treatment, storage, transportation and disposal of solid and hazardous wastes and hazardous materials, and impose obligations to investigate and remediate contamination in certain circumstances. Liabilities relating to investigation and remediation of contamination, as well as other liabilities concerning hazardous materials or contamination such as claims for personal injury or property damage, may arise at many locations, including formerly owned or operated properties and sites where wastes have been treated or disposed of, as well as properties we currently own or operate. Such liabilities may arise even where the contamination does not result from noncompliance with applicable environmental laws. Under a number of environmental laws, such liabilities may also be joint and several, meaning that a party can be held responsible for more than its share of the liability involved, or even the entire share. Environmental requirements generally have become more stringent in recent years, and compliance with those requirements more expensive.
We have incurred expenses in connection with environmental compliance, and we anticipate that we will continue to do so in the future. Failure to comply with the extensive environmental laws and regulations applicable to us could result in significant civil or criminal penalties and remediation costs. Our assets and operations also involve the use of materials classified as hazardous, toxic or otherwise dangerous. Some of our facilities and properties are located near environmentally sensitive areas such as wetlands and habitats of endangered or threatened species. In addition, certain properties in which we operate are, or are suspected of being, affected by environmental contamination. Compliance with these laws and regulations, and liabilities concerning contamination or hazardous materials, may adversely affect our costs and, therefore, our business, financial condition and results of operations.
In addition, claims have been made or threatened against electric utilities for bodily injury, disease or other damages allegedly related to exposure to electromagnetic fields associated with electric transmission and distribution lines. We cannot provide assurance that such claims will not be asserted against us or that, if determined in a manner adverse to our interests, such claims would not have a material effect on our business, financial condition and results of operations.
We are subject to various regulatory requirements, including reliability standards; contract filing requirements; reporting, recordkeeping and accounting requirements; and transaction approval requirements. Violations of these requirements, whether intentional or unintentional, may result in penalties that, under some circumstances, could have a material adverse effect on our business, financial condition, results of operations and cash flows.
The various regulatory requirements to which we are subject include reliability standards established by the NERC, which acts as the nation’s Electric Reliability Organization approved by the FERC in accordance with Section 215 of the FPA. These standards address operation, planning and security of the bulk power system, including requirements with respect to real-time transmission operations, emergency operations, vegetation management, critical infrastructure protection and personnel training. Failure to comply with these requirements can result in monetary penalties as well as non-monetary sanctions. Monetary penalties vary based on an assigned risk factor for each potential violation, the severity of the violation and various other circumstances, such as whether the violation was intentional or concealed, whether there are repeated violations, the degree of the violator’s cooperation in investigating and remediating the violation and the presence of a compliance program, and such penalties can be substantial. Non-monetary sanctions include potential limitations on the violator’s activities or operation and placing the violator on a watchlist for major violators. Despite our best efforts to comply and the implementation of a compliance program intended to ensure reliability, there can be no assurance that violations will not occur that would result in material penalties or sanctions. If any of our subsidiaries were to violate the NERC reliability standards, even unintentionally, in any material way, any penalties or sanctions imposed against us could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Certain of our subsidiaries are also subject to requirements under Sections 203 and 205 of the FPA for approval of transactions; reporting, recordkeeping and accounting requirements; and for filing contracts related to the provision of jurisdictional services. Under FERC policy, failure to file jurisdictional agreements on a timely basis may result in foregoing the time value of revenues collected under the agreement, but not to the point where a loss would be incurred. The failure to obtain timely approval of transactions subject to FPA Section 203, or to comply with applicable reporting, recordkeeping or accounting requirements under FPA Section 205, could subject


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us to penalties that could have a material adverse effect on our financial condition, results of operations and cash flows.
Acts of war, terrorist attacks, cyber attacks, natural disasters, severe weather and other catastrophic events may have a material adverse effect on our business, financial condition, results of operations and cash flows.
Acts of war, terrorist attacks, cyber attacks, natural disasters, severe weather and other catastrophic events may negatively affect our business, financial condition and cash flows in unpredictable ways, such as increased security measures and disruptions of markets. Energy related assets, including, for example, our transmission facilities and DTE Electric’s, Consumers Energy’s and IP&L’s generation and distribution facilities that we interconnect with, may be at risk of acts of war, terrorist attacks and cyber attacks, as well as natural disasters, severe weather and other catastrophic events. In addition to any physical damage caused by such events, cyber attacks targeting our information systems could impair our records, networks, systems and programs, or transmit viruses to other systems. Such events or the threat of such events may increase costs associated with heightened security requirements. In addition, such events or threats may have a material effect on the economy in general and could result in a decline in energy consumption, which may have a material adverse effect on our business, financial condition, results of operations and cash flows.
Changes in tax laws or regulations may negatively affect our results of operations, net income, financial condition and cash flows.
We are subject to taxation by various taxing authorities at the federal, state and local levels. The Trump Administration has made federal corporate tax reform one of its priorities and the possibility of such reform is thought to be increased in light of the Republican-led Congress. While such reform is likely to be favorable to corporations generally, the structure of any such reform is unknown and a change in tax laws or rates could in fact adversely affect our results of operations, net income, financial condition and cash flows. For example, federal bonus depreciation is currently available for property acquired and placed in service through 2019, with certain provisions that allow for an additional year of eligibility for certain property with long construction periods. If tax reform results in extending accelerated tax depreciation similar to the provisions of bonus depreciation, the higher deferred tax liabilities and the corresponding reduced rate base would have a negative effect on our annual revenues and net income over the tax lives of the eligible assets. Additionally, we have a considerable amount of debt, including debt at ITC Holdings, and any change in tax laws or regulations that reduce the deduction of interest expense for income tax purposes could have a negative effect on our net income. We cannot predict the timing or structure of tax-related developments.
Risks Relating to Our Corporate and Financial Structure
ITC Holdings is a holding company with no operations, and unless we receive dividends or other payments from our subsidiaries, we may be unable to fulfill our cash obligations.
As a holding company with no business operations, ITC Holdings’ material assets consist primarily of the stock and membership interests in our subsidiaries. Our only sources of cash are dividends and other payments received by us from time to time from our subsidiaries, proceeds raised from the sale of our securities and borrowings under our various credit agreements. Each of our subsidiaries, however, is legally distinct from us and has no obligation, contingent or otherwise, to make funds available to us. The ability of each of our Regulated Operating Subsidiaries and our other subsidiaries to pay dividends and make other payments to us is subject to, among other things, the availability of funds, after taking into account capital expenditure requirements, the terms of its indebtedness, applicable state laws and regulations of the FERC and the FPA. Our Regulated Operating Subsidiaries target a FERC-approved capital structure of 60% equity and 40% debt that may limit the ability of our Regulated Operating Subsidiaries to use net assets for the payment of dividends to ITC Holdings. In addition, ITC Holdings’ right to receive any assets of any subsidiary, and therefore the right of its creditors to participate in those assets, will be effectively subordinated to the claims of that subsidiary’s creditors. If ITC Holdings does not receive cash or other assets from our subsidiaries, it may be unable to pay principal and interest on its indebtedness.



20

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

We have a considerable amount of debt and our consolidated indebtedness includes various debt securities and borrowings, which utilize indentures, revolving credit agreements and commercial paper, that we rely on as sources of capital and liquidity. This financing strategy can have several important consequences, including, but not limited to, the following:
•
If future cash flows are insufficient, we may not be able to make principal or interest payments on our debt obligations, which could result in the occurrence of an event of default under one or more of those debt instruments.
•
We may need to increase our indebtedness in order to make the capital expenditures and other expenses or investments planned by us.
•
Our indebtedness has the general effect of reducing our flexibility to react to changing business and economic conditions insofar as they affect our financial condition. A substantial portion of the dividends and payments in lieu of taxes we receive from our subsidiaries will be dedicated to the payment of interest on our indebtedness, thereby, reducing the funds available for working capital and capital expenditures.
•
We currently have debt instruments outstanding with short-term maturities or relatively short remaining maturities. Our ability to secure additional financing prior to or after these facilities mature, if needed, may be substantially restricted by the existing level of our indebtedness and the restrictions contained in our debt instruments. Additionally, the interest rates at which we might secure additional financings may be higher than our currently outstanding debt instruments or higher than forecasted at any point in time, which could adversely affect our business, financial condition, results of operations and cash flows.
•
Market conditions could affect our access to capital markets, restrict our ability to secure financing to make the capital expenditures and investments and pay other expenses planned by us which could adversely affect our business, financial condition, cash flows and results of operations.
We may incur substantial additional indebtedness in the future. The incurrence of additional indebtedness would increase the risks described above.
Certain provisions in our debt instruments limit our financial and operating flexibility.
Our debt instruments on a consolidated basis, including senior notes, secured notes, first mortgage bonds, revolving credit agreements and commercial paper, contain numerous financial and operating covenants that place significant restrictions on, among other things, our ability to:
•
incur additional indebtedness;
•
engage in sale and lease-back transactions;
•
create liens or other encumbrances;
•
enter into mergers, consolidations, liquidations or dissolutions, or sell or otherwise dispose of all or substantially all of our assets;
•
create and acquire subsidiaries; and
•
pay dividends or make distributions on our stock or on the stock or member capital of our subsidiaries.
Our debt instruments also require us to meet certain financial ratios, such as maintaining certain debt to capitalization ratios. Our ability to comply with these and other requirements and restrictions may be affected by changes in economic or business conditions, results of operations or other events beyond our control. A failure to comply with the obligations contained in any of our debt instruments could result in acceleration of related debt and the acceleration of debt under other instruments evidencing indebtedness that may contain cross-acceleration or cross-default provisions.
Adverse changes in our credit ratings may negatively affect us.
Our ability to access capital markets is important to our ability to operate our business. Increased scrutiny of the energy industry and the impact of regulation, as well as changes in our financial performance and unfavorable


21

conditions in the capital markets could result in credit agencies reexamining our credit ratings. A downgrade in our credit ratings could restrict or discontinue our ability to access capital markets at attractive rates and increase our borrowing costs. A rating downgrade could also increase the interest we pay on commercial paper and under our revolving credit agreements.
Risks Related to the Merger
ITC Holdings and its subsidiaries are subject to business uncertainties during the period of integration with Fortis that could adversely affect ITC Holdings’ financial results.
Uncertainty about the effect of the Merger on employees or vendors and others, including contractors, may have an adverse effect on us. These uncertainties may impair our ability to attract, retain and motivate key personnel, and could cause vendors, contractors and others that deal with us to seek to change existing business relationships. Employee retention may be challenging, as employees may experience uncertainty about their future roles with the combined company. If, despite our retention efforts, key employees retire or depart due to the uncertainty of employment and difficulty of integration or a desire not to remain with the combined company, we may incur significant costs in identifying, hiring, and retaining replacements for departing employees, which could have a material adverse effect on our business operations and financial results. In addition, integration-related issues may place a significant burden on management, employees and internal resources which could otherwise have been devoted to other business opportunities. The diversion of management’s attention and any delays or difficulties encountered in connection with the Merger and the integration of ITC Holdings’ operations with Fortis could have an adverse effect on our business, financial results or financial condition. The integration process may also result in additional and unforeseen expenses.
We are the target of securities class action and derivative lawsuits, which could result in substantial costs and diversion of management’s time and resources.
Securities class action lawsuits and derivative lawsuits are often brought against companies that have entered into merger agreements. There is currently a class action lawsuit pending against us and our directors in connection with the Merger, as described in Note 15 to the consolidated financial statements. We are not able to predict the outcome of this action or others that may be brought, nor can we predict the amount of time and expense that will be required to resolve the actions. Even if we believe the lawsuits are without merit, defending against or settling these claims can result in substantial costs to us and divert management’s time and resources.
ITEM 1B.     UNRESOLVED STAFF COMMENTS.
None.
ITEM 2.    PROPERTIES.
Our Regulated Operating Subsidiaries’ transmission facilities are located in Michigan and portions of Iowa, Minnesota, Illinois, Missouri, Kansas and Oklahoma. Our MISO Regulated Operating Subsidiaries and ITC Great Plains have agreements with other utilities for the joint ownership of specific substations, transmission lines and other transmission assets. See Note 14 to the consolidated financial statements for more information on the jointly owned assets.
ITCTransmission owns the assets of a transmission system and related assets, including:
•
approximately 3,100 circuit miles of overhead and underground transmission lines rated at voltages of 120 kV to 345 kV;
•
approximately 18,700 transmission towers and poles;
•
station assets, such as transformers and circuit breakers, at 185 stations and substations which either interconnect ITCTransmission’s transmission facilities or connect ITCTransmission’s facilities with generation or distribution facilities owned by others;
•
other transmission equipment necessary to safely operate the system (e.g., monitoring and metering equipment);
•
warehouses and related equipment;
•
associated land held in fee, rights-of-way and easements;


22

•
an approximately 188,000 square-foot corporate headquarters facility and operations control room in Novi, Michigan, including furniture, fixtures and office equipment; and
•
an approximately 40,000 square-foot facility in Ann Arbor, Michigan that includes a back-up operations control room.
ITCTransmission’s First Mortgage Bonds are issued under ITCTransmission’s first mortgage and deed of trust. As a result, the bondholders have the benefit of a first mortgage lien on substantially all of ITCTransmission’s property.
METC owns the assets of a transmission system and related assets, including:
•
approximately 5,600 circuit miles of overhead transmission lines rated at voltages of 120 kV to 345 kV;
•
approximately 37,000 transmission towers and poles;
•
station assets, such as transformers and circuit breakers, at 104 stations and substations which either interconnect METC’s transmission facilities or connect METC’s facilities with generation or distribution facilities owned by others;
•
other transmission equipment necessary to safely operate the system (e.g., monitoring and metering equipment); and
•
warehouses and related equipment.

METC's Senior Secured Notes are issued under METC's first mortgage indenture. As a result, the noteholders have the benefit of a first mortgage lien on substantially all of METC's property.
METC does not own the majority of the land on which its assets are located, but under the provisions of its Easement Agreement with Consumers Energy, METC has an easement to use the land, rights-of-way, leases and licenses in the land on which its transmission lines are located that are held or controlled by Consumers Energy. See “Item 1 Business — Operating Contracts — METC — Amended and Restated Easement Agreement.”
ITC Midwest owns the assets of a transmission system and related assets, including:
•
approximately 6,600 circuit miles of transmission lines rated at voltages of 34.5 kV to 345 kV;
•
transmission towers and poles;
•
station assets, such as transformers and circuit breakers, at approximately 276 stations and substations which either interconnect ITC Midwest’s transmission facilities or connect ITC Midwest’s facilities with generation or distribution facilities owned by others;
•
other transmission equipment necessary to safely operate the system (e.g., monitoring and metering equipment);
•
warehouses and related equipment; and
•
associated land held in fee, rights-of-way and easements.
ITC Midwest’s First Mortgage Bonds are issued under ITC Midwest’s first mortgage and deed of trust. As a result, the bondholders have the benefit of a first mortgage lien on substantially all of ITC Midwest’s property.
ITC Great Plains owns transmission and related assets including:
•
approximately 470 miles of transmission lines rated at a voltage of 345 kV;
•
approximately 1,910 transmission towers and poles;
•
station assets, such as transformers and circuit breakers, at 9 stations and substations which either interconnect ITC Great Plains’ transmission facilities or connect ITC Great Plains’ facilities with transmission, generation or distribution facilities owned by others;
•
other transmission equipment necessary to safely operate the system (e.g., monitoring and metering equipment); and
•
associated land held in fee, rights-of-way and easements.


23

ITC Great Plains’ First Mortgage Bonds are issued under ITC Great Plains’ first mortgage and deed of trust. As a result, the bondholders have the benefit of a first mortgage lien on substantially all of ITC Great Plains’ property.
ITC Interconnection owns certain substation assets and less than a mile of a transmission line rated at a voltage of 345 kV in Michigan. As of December 31, 2016, there were no liens or encumbrances on the assets of ITC Interconnection.
The assets of our Regulated Operating Subsidiaries are suitable for electric transmission and adequate for the electricity demand in our service territory. We prioritize capital spending based in part on meeting reliability standards within the industry. This includes replacing and upgrading existing assets as needed.
ITEM 3.     LEGAL PROCEEDINGS.
We are involved in certain legal proceedings before various courts, governmental agencies and mediation panels concerning matters arising in the ordinary course of business. These proceedings include certain contract disputes, regulatory matters and pending judicial matters. We cannot predict the final disposition of such proceedings. We regularly review legal matters and record provisions for claims that are considered probable of loss.
Refer to Notes 5 and 15 to the consolidated financial statements for a description of certain pending legal proceedings, which description is incorporated herein by reference.
ITEM 4.     MINE SAFETY DISCLOSURES.
Not applicable.
PART II
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
With the consummation of the Merger on October 14, 2016, ITC Holdings became a wholly-owned subsidiary of Investment Holdings and ITC Holdings’ common stock was delisted from NYSE. Consequently, there is no longer any public trading market for the common stock of ITC Holdings. Prior to the closing of the Merger, the common stock of ITC Holdings was traded on the NYSE under the symbol ITC. The following tables set forth the high and low sales price per share of the common stock for each full quarterly period in 2015 and 2016 (through October 14, 2016), as reported on the NYSE, and the cash dividends per share paid during the periods indicated.
Year Ended December 31, 2016
 
High
 
Low
 
Dividends
October 1 through October 14, 2016
 
$
46.48

 
$
44.91

 
$
—

Quarter ended September 30, 2016
 
47.46

 
44.64

 
0.2155

Quarter ended June 30, 2016
 
46.89

 
42.44

 
0.1875

Quarter ended March 31, 2016
 
43.89

 
36.53

 
0.1875

 
 
 
 
 
 
 
Year Ended December 31, 2015
 
High
 
Low
 
Dividends
Quarter ended December 31, 2015
 
$
39.60

 
$
30.33

 
$
0.1875

Quarter ended September 30, 2015
 
35.68

 
31.16

 
0.1875

Quarter ended June 30, 2015
 
37.12

 
30.64

 
0.1625

Quarter ended March 31, 2015
 
44.00

 
35.54

 
0.1625

Additionally, ITC Holdings paid dividends of $33 million to Investment Holdings during the fourth quarter of 2016. ITC Holdings also paid dividends of $33 million to Investment Holdings in January 2017. The debt agreements to which we are a party contain numerous financial covenants that could limit ITC Holdings’ ability to pay dividends. Further, each of our subsidiaries is legally distinct from ITC Holdings and has no obligation, contingent or otherwise, to make funds available to ITC Holdings.
There were no share repurchases for the period from October 1, 2016 through the closing of the Merger.


24

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)
2016
 
2015
 
2014
 
2013
 
2012
OPERATING REVENUES (a) (b) (c)
$
1,125

 
$
1,045

 
$
1,023

 
$
941

 
$
831

OPERATING EXPENSES
 
 
 
 
 
 
 
 
 
Operation and maintenance
114

 
113

 
112

 
113

 
122

General and administrative (d) (e) (f)
239

 
145

 
115

 
149

 
112

Depreciation and amortization
158

 
145

 
128

 
119

 
107

Taxes other than income taxes
93

 
82

 
76

 
66

 
60

Other operating income and expense — net
(1
)
 
(1
)
 
(1
)
 
(2
)
 
(2
)
Total operating expenses
603

 
484

 
430

 
445

 
399

OPERATING INCOME
522

 
561

 
593

 
496

 
432

OTHER EXPENSES (INCOME)
 
 
 
 
 
 
 
 
 
Interest expense — net
211

 
204

 
187

 
168

 
156

Allowance for equity funds used during construction
(35
)
 
(28
)
 
(21
)
 
(30
)
 
(23
)
Loss on extinguishment of debt
—

 
—

 
29

 
—

 
—

Other income
(2
)
 
(2
)
 
(1
)
 
(1
)
 
(2
)
Other expense
5

 
3

 
5

 
7

 
4

Total other expenses (income)
179

 
177

 
199

 
144

 
135

INCOME BEFORE INCOME TAXES
343

 
384

 
394

 
352

 
297

INCOME TAX PROVISION
97

 
142

 
150

 
119

 
109

NET INCOME
$
246

 
$
242

 
$
244

 
$
233

 
$
188

 
ITC Holdings and Subsidiaries
 
As of December 31,
(In millions)
2016
 
2015
 
2014
 
2013
 
2012
BALANCE SHEET DATA:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
8

 
$
14

 
$
28

 
$
34

 
$
26

Working capital (deficit) (g)
(400
)
 
(550
)
 
(291
)
 
(325
)
 
(828
)
Property, plant and equipment — net
6,698

 
6,110

 
5,497

 
4,847

 
4,135

Goodwill
950

 
950

 
950

 
950

 
950

Total assets (g) (h)
8,223

 
7,555

 
6,932

 
6,241

 
5,525

Debt:
 
 
 
 
 
 
 
 
 
ITC Holdings (h)
2,387

 
2,304

 
2,123

 
1,871

 
1,683

Regulated Operating Subsidiaries (h)
2,203

 
2,125

 
1,954

 
1,717

 
1,448

Total debt (h)
4,590

 
4,429

 
4,077

 
3,588

 
3,131

Total stockholders’ equity
$
1,901

 
$
1,709

 
$
1,670

 
$
1,614

 
$
1,415

 
ITC Holdings and Subsidiaries
 
Year Ended December 31,
(In millions)
2016
 
2015
 
2014
 
2013
 
2012
CASH FLOWS DATA:
 
 
 
 
 
 
 
 
 
Expenditures for property, plant and equipment
$
750

 
$
701

 
$
753

 
$
824

 
$
814

____________________________
(a)
During 2016, 2015 and 2014, we recognized an aggregate estimated regulatory liability for the refund and potential refund relating to the rate of return on equity complaints as described in Note 15 to the consolidated


25

financial statements, which resulted in a reduction in operating revenues of $80 million, $115 million and $47 million, respectively.
(b)
During 2015, we recognized a regulatory liability for the refund relating to the formula rate template modifications filing as described in Note 5 to the consolidated financial statements, which resulted in a reduction in operating revenues of $10 million.
(c)
During 2012, we initially recognized the FERC audit refund liability, which resulted in a reduction in operating revenues of $11 million.
(d)
During 2016, we expensed external legal, advisory and financial services fees of $55 million related to the Merger and approximately $41 million due to the accelerated vesting of the share-based awards that occurred at the completion of the Merger. See Note 2 to the consolidated financial statements for further details on the impact of the Merger. The external and internal costs related to the Merger were recorded at ITC Holdings and have not been included as components of revenue requirement at our Regulated Operating Subsidiaries.
(e)
The increase in general and administrative expenses in 2015 was due primarily to higher compensation related expenses, including the development bonuses described below under “Recent Developments — Development Bonuses,” and higher legal and advisory professional service fees for various development initiatives.
(f)
During 2013 and 2012, we expensed external legal, advisory and financial services fees of $43 million and $19 million, respectively, recorded within general and administrative expenses related to a proposed transaction whereby the electric transmission business of Entergy Corporation was to be separated and subsequently merged with a wholly-owned subsidiary of ITC Holdings. The proposed transaction was terminated in December 2013. The external and internal costs related to the proposed transaction with Entergy Corporation were recorded at ITC Holdings and were not included as components of revenue requirement at our Regulated Operating Subsidiaries.
(g)
All amounts presented reflect the change in the authoritative guidance issued by the Financial Accounting Standards Board to net all deferred income tax assets and liabilities and present as a single line item within non-current assets or liabilities on the balance sheet. This change was adopted retrospectively by us in 2015.
(h)
All amounts presented reflect the change in authoritative guidance on the presentation of debt issuance costs on the balance sheet. This change was adopted retrospectively by us in 2016. Refer to Notes 3 and 9 of the consolidated financial statements for more information.
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
Safe Harbor Statement Under The Private Securities Litigation Reform Act of 1995
Our reports, filings and other public announcements contain certain statements that describe our management’s beliefs concerning future business conditions, plans and prospects, growth opportunities, the outlook for our business and the electric transmission industry, expectations with respect to various legal and regulatory proceedings and the Merger based upon information currently available. Such statements are “forward-looking” statements within the meaning of the Private Securities Litigation Reform Act of 1995. Wherever possible, we have identified these forward-looking statements by words such as “will,” “may,” “anticipates,” “believes,” “intends,” “estimates,” “expects,” “projects,” “likely” and similar phrases. These forward-looking statements are based upon assumptions our management believes are reasonable. Such forward-looking statements are based on estimates and assumptions and subject to significant risks and uncertainties which could cause our actual results, performance and achievements to differ materially from those expressed in, or implied by, these statements, including, among others, the risks and uncertainties listed in this report under “Item 1A Risk Factors” and in our other reports filed with the SEC from time to time.
Forward-looking statements speak only as of the date made and can be affected by assumptions we might make or by known or unknown risks and uncertainties. Many factors mentioned in our discussion in this report will be important in determining future results. Consequently, we cannot assure you that our expectations or forecasts expressed in such forward-looking statements will be achieved. Except as required by law, we undertake no obligation to publicly update any of our forward-looking or other statements, whether as a result of new information, future events or otherwise.


26

Overview
Through our Regulated Operating Subsidiaries, we operate high-voltage systems in Michigan and portions of Iowa, Minnesota, Illinois, Missouri, Kansas and Oklahoma that transmit electricity from generating stations to local distribution facilities connected to our systems. Our business strategy is to operate, maintain and invest in transmission infrastructure in order to enhance system integrity and reliability, reduce transmission constraints and upgrade the transmission networks to support new generating resources interconnecting to our transmission systems. We also are pursuing development projects not within our existing systems, which are likewise intended to improve overall grid reliability, reduce transmission constraints and facilitate interconnections of new generating resources, as well as enhance competitive wholesale electricity markets.
As electric transmission utilities regulated by the FERC, our Regulated Operating Subsidiaries earn revenues for the use of their electric transmission systems by our customers. We derive nearly all of our revenues from providing electric transmission service over our Regulated Operating Subsidiaries’ transmission systems to investor-owned utilities, such as DTE Electric, Consumers Energy and IP&L, and other entities, such as alternative electricity suppliers, power marketers and other wholesale customers that provide electricity to end-use consumers as well as from transaction-based capacity reservations on our transmission systems.
As independent transmission companies, our Regulated Operating Subsidiaries are subject to rate regulation only by the FERC, and our cost-based rates are discussed in “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cost-Based Formula Rates with True-Up Mechanism.”
Our Regulated Operating Subsidiaries’ primary operating responsibilities include maintaining, improving and expanding their transmission systems to meet their customers’ ongoing needs, scheduling outages on system elements to allow for maintenance and construction, maintaining appropriate system voltages and monitoring flows over transmission lines and other facilities to ensure physical limits are not exceeded.
Significant recent matters that influenced our financial position and results of operations and cash flows for the year ended December 31, 2016 or that may affect future results include:
•
Our capital expenditures of $750 million at our Regulated Operating Subsidiaries during the year ended December 31, 2016, resulting primarily from our focus on improving system reliability, increasing system capacity and upgrading the transmission network to support new generating resources;
•
Debt issuances as described in Note 9 to the consolidated financial statements, including commercial paper issued under ITC Holdings’ commercial paper program, and borrowings under our revolving and term loan credit agreements in 2016 and 2015 to fund capital investment at our Regulated Operating Subsidiaries as well as for general corporate purposes;
•
Debt maturing within one year of $235 million and the potentially higher interest rates associated with the additional financing required to repay this debt as discussed in Note 9 to the consolidated financial statements;
•
Recognition of the liability for the refund and potential refund relating to the rate of return on equity (“ROE”) complaints, as described in Note 15 to the consolidated financial statements, which resulted in a total estimated pre-tax reduction of revenue and additional interest of $90 million and $120 million and an estimated after-tax reduction to net income of $55 million and $73 million for the years ended December 31, 2016 and 2015, respectively. On February 14, 2017, our MISO Regulated Operating Subsidiaries provided $119 million to MISO to fund the payment of the refund, including interest, for the initial ROE complaint;
•
Election of bonus depreciation for tax years 2015 and 2016. The total impact from these matters was lower revenues of approximately $20 million and lower net income of approximately $12 million for the year ended December 31, 2016. These matters also resulted in additional net deferred income tax liabilities of approximately $109 million and a corresponding income tax receivable of $12 million as of December 31, 2016, and income tax refunds of $128 million, which were received in August 2016; and
•
As a result of the Merger consummated on October 14, 2016, ITC Holdings became an indirect subsidiary of Fortis as described below under “Recent Developments — The Merger.” For the year ended December 31, 2016, we expensed external legal, advisory and financial services fees related to the Merger of $55 million and certain internal labor and associated costs related to the Merger of approximately $58 million, including approximately $41 million of expense recognized due to the accelerated vesting of the share-based awards described in Note 13 to the consolidated financial statements. These merger-related costs were


27

recorded within general and administrative expenses. Certain amounts of the external costs are not expected to be deductible for income tax purposes. The external and internal costs related to the Merger were recorded at ITC Holdings and have not been included as components of revenue requirement at our Regulated Operating Subsidiaries.
These items are discussed in more detail throughout “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Cost-Based Formula Rates with True-Up Mechanism
Our Regulated Operating Subsidiaries calculate their revenue requirements using cost-based formula rates and are effective without the need to file rate cases with the FERC, although the rates are subject to legal challenge at the FERC. Under their cost-based formula rates, each of our Regulated Operating Subsidiaries separately calculates a revenue requirement based on financial information specific to each company. The calculation of projected revenue requirement for a future period is used to establish the transmission rate used for billing purposes. The calculation of actual revenue requirements for a historic period is used to calculate the amount of revenues recognized in that period and determine the over- or under-collection for that period.
Under these formula rates, our Regulated Operating Subsidiaries recover expenses and earn a return on and recover investments in property, plant and equipment on a current basis, rather than lagging. The formula rate for a given year initially utilizes forecasted expenses, property, plant and equipment, point-to-point revenues, network load at our MISO Regulated Operating Subsidiaries and other items for the upcoming calendar year to establish projected revenue requirements for each of our Regulated Operating Subsidiaries that are used as the basis for billing for service on their systems from January 1 to December 31 of that year. Our rates include a true-up mechanism, whereby our Regulated Operating Subsidiaries compare their actual revenue requirements to their billed revenues for each year to determine any over- or under-collection of revenue. The over- or under-collection typically results from differences between the projected revenue requirement used as the basis for billing and actual revenue requirement at each of our Regulated Operating Subsidiaries, or from differences between actual and projected monthly peak loads at our MISO Regulated Operating Subsidiaries. In the event billed revenues in a given year are more or less than actual revenue requirements, which are calculated primarily using information from that year’s FERC Form No. 1, our Regulated Operating Subsidiaries will refund or collect additional revenues, with interest, within a two-year period such that customers pay only the amounts that correspond to actual revenue requirements for that given period. This annual true-up ensures that our Regulated Operating Subsidiaries recover their allowed costs and earn their allowed returns.
Illustrative Example of Formula Rate Setting
The formula rate setting example shown below is for illustrative purposes and not based on our actual financial data.
Line
Item
Instructions
Amount
1
Rate base (a)
 
$
1,000,000

2
Multiply by 13-month weighted average cost of capital (b)
 
8.81
%
3
Allowed return on rate base
(Line 1 x Line 2)
$
88,100

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

5
Income taxes (c)
 
50,000

6
Gross revenue requirement
(Line 3 + Line 4 + Line 5)
$
288,100

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


28

(b)
The weighted average cost of capital for purposes of this illustration is calculated below. The cost of capital for debt is included at a flat interest rate for purposes of this illustration and is not based on our actual cost of capital. The cost of capital rate for equity represents the current maximum allowed MISO ROE rate. See Note 15 to the consolidated financial statements for detail on ROE matters, including pending ROE complaints.
 
 
 
 
 
Weighted
 
 
 
 
 
Average
 
Percentage of
 
 
 
Cost of
 
Total Capitalization
 
Cost of Capital
 
Capital
Debt
40.00%
 
5.00% =
 
2.00
%
Equity
60.00%
 
11.35% =
 
6.81
%
 
100.00%
 
 
 
8.81
%
(c)
Represents an approximation of the federal and state income tax expense for purposes of this illustration and is not based on our actual tax expense.
Revenue Accruals and Deferrals — Effects of Monthly Peak Loads
For our MISO Regulated Operating Subsidiaries, monthly peak loads are used for billing network revenues, which currently is the largest component of our operating revenues. One of the primary factors that impacts the revenue accruals and deferrals at our MISO Regulated Operating Subsidiaries is actual monthly peak loads experienced as compared to those forecasted in establishing the annual network transmission rate. Under their cost-based formula rates that contain a true-up mechanism, our Regulated Operating Subsidiaries accrue or defer revenues to the extent that their actual revenue requirement for the reporting period is higher or lower, respectively, than the amounts billed relating to that reporting period. Although monthly peak loads do not impact operating revenues recognized, network load affects the timing of our cash flows from transmission service. The monthly peak load of our MISO Regulated Operating Subsidiaries is generally impacted by weather and economic conditions and seasonally shaped with higher load in the summer months when cooling demand is higher.
ITC Great Plains does not receive revenue based on a peak load or a dollar amount per kW each month and, therefore, peak load does not have a seasonal effect on operating cash flows. The SPP tariff applicable to ITC Great Plains is billed ratably each month based on its annual projected revenue requirement posted annually by SPP.
Capital Investment and Operating Results Trends
We expect a long-term upward trend in revenues and earnings, subject to the impact of any rate changes and required refunds resulting from the resolution of the ROE complaints as described in Note 15 to the consolidated financial statements. The primary factor that is expected to continue to increase our revenues and earnings in future years is increased rate base that would result from our anticipated capital investment, in excess of depreciation, from our Regulated Operating Subsidiaries’ long-term capital investment programs to improve reliability, increase system capacity and upgrade the transmission network to support new generating resources. In addition, our capital investment efforts relating to development initiatives are based on establishing an ongoing pipeline of projects that would position us for long-term growth. Investments in property, plant and equipment, when placed in-service upon completion of a capital project, are added to the rate base of our Regulated Operating Subsidiaries.
Our Regulated Operating Subsidiaries strive for high reliability of their systems and improvement in system accessibility for all generation resources. The FERC requires compliance with certain reliability standards and may take enforcement actions against violators, including the imposition of substantial fines. NERC is responsible for developing and enforcing these mandatory reliability standards. We continually assess our transmission systems against standards established by NERC, as well as the standards of applicable regional entities under NERC that have been delegated certain authority for the purpose of proposing and enforcing reliability standards. We believe that we meet the applicable standards in all material respects, although further investment in our transmission systems and an increase in maintenance activities will likely be needed to maintain compliance, improve reliability and address any new standards that may be promulgated.
We also assess our transmission systems against our own planning criteria that are filed annually with the FERC. Based on our planning studies, we see needs to make capital investments to (1) rebuild existing property, plant and equipment; (2) upgrade the system to address demographic changes that have impacted transmission load and the changing role that transmission plays in meeting the needs of the wholesale market, including


29

accommodating the siting of new generation or increasing import capacity to meet changes in peak electrical demand; (3) relieve congestion in the transmission systems; and (4) achieve state and federal policy goals, such as renewable generation portfolio standards. The following table shows our actual and expected capital expenditures:
 
 
Actual Capital
 
Forecasted
 
 
Expenditures for the
 
Capital
 
 
year ended
 
Expenditures
(In millions)
 
December 31, 2016
 
2017 — 2021
Expenditures for property, plant and equipment (a)
 
$
750

 
$
2,812

____________________________
(a)
Amounts represent the cash payments to acquire or construct property, plant and equipment, as presented in the consolidated statements of cash flows. These amounts do not include non-cash additions to property, plant and equipment for the allowance for equity funds used during construction as well as accrued liabilities for construction, labor and materials that have not yet been paid.
Refer to “Item 1 Business — Development of Business — Development Projects” for discussion of our development projects. We are pursuing projects that could result in a significant amount of capital investment, but are not able to estimate the amounts we ultimately expect to achieve or the timing of such investments.
Investments in property, plant and equipment could vary due to, among other things, the impact of actual loads, forecasted loads, regional economic conditions, weather conditions, union strikes, labor shortages, material and equipment prices and availability, our ability to obtain any necessary financing for such expenditures, limitations on the amount of construction that can be undertaken on our systems at any one time, regulatory approvals for reasons relating to rate construct, environmental, siting, regional planning, cost recovery or other issues or as a result of legal proceedings, variances between estimated and actual costs of construction contracts awarded and the potential for greater competition for new development projects. In addition, investments in transmission network upgrades for generator interconnection projects could change from prior estimates significantly due to changes in the MISO queue for generation projects and other factors beyond our control.
Recent Developments
The Merger
On February 9, 2016, ITC Holdings entered into the Merger Agreement with Fortis, FortisUS and Merger Sub. On April 20, 2016, Fortis reached a definitive agreement with a subsidiary of GIC for GIC to acquire an indirect 19.9% equity interest in ITC Holdings upon completion of the Merger. On October 14, 2016, ITC Holdings and Fortis completed the Merger contemplated by the Merger Agreement. On the same date, the common shares of ITC Holdings were delisted from the NYSE and the common shares of Fortis were listed and began trading on the NYSE. Fortis continues to have its shares listed on the Toronto Stock Exchange. As a result of the Merger, Merger Sub merged with and into ITC Holdings with ITC Holdings continuing as the surviving corporation and becoming a majority owned indirect subsidiary of Fortis. In the Merger, ITC Holdings shareholders received $22.57 in cash and 0.7520 Fortis common shares for each share of common stock of ITC Holdings. Refer to Note 2 to the consolidated financial statements for further details on the Merger.
ITC Interconnection
ITC Interconnection was formed in 2014 by ITC Holdings to pursue transmission investment opportunities. On June 1, 2016, ITC Interconnection acquired certain transmission assets from a merchant generating company and placed a newly constructed 345 kV transmission line in service. As a result, ITC Interconnection became a transmission owner in the FERC-approved RTO, PJM Interconnection, and is subject to rate-regulation by the FERC. The revenues earned by ITC Interconnection are based on its facilities reimbursement agreement with the merchant generating company. The financial results of ITC Interconnection are currently not material to our consolidated financial statements.


30

Development Bonuses
During 2016, 2015 and 2014, we recognized general and administrative expenses of $1 million, $11 million and $3 million, respectively, for bonuses for certain development projects, including the successful completion of certain milestones relating to projects at ITC Great Plains.
Rate of Return on Equity Complaints
On November 12, 2013, certain parties (the “complainants”) filed a joint complaint with the FERC under Section 206 of the FPA (the “Initial Complaint”), requesting that the FERC find the then current 12.38% MISO regional base ROE rate (the “base ROE”) for all MISO TOs, including ITCTransmission, METC and ITC Midwest, to no longer be just and reasonable. The complainants sought a FERC order reducing the base ROE used in the formula transmission rates for our MISO Regulated Operating Subsidiaries to 9.15%, reducing the equity component of our capital structure from the FERC approved 60% to 50% and terminating the ROE adders approved for certain ITC Holdings Regulated Operating Subsidiaries, including adders currently utilized by ITCTransmission and METC.
On October 16, 2014, the FERC granted the complainants’ request in part by setting the base ROE for hearing and settlement procedures, while denying all other aspects of the Initial Complaint. The FERC also denied the request to terminate ITCTransmission’s and METC’s ROE incentives, subject to the top end of a zone of reasonableness. The FERC set the refund effective date for the Initial Complaint as November 12, 2013.
On December 22, 2015, the presiding administrative law judge issued an initial decision on the Initial Complaint. On September 28, 2016, the FERC issued an order (the “September 2016 Order”) affirming the presiding administrative law judge’s initial decision and setting the base ROE at 10.32%, with a maximum ROE of 11.35%, effective for the period from November 12, 2013 through February 11, 2015 (the “Initial Refund Period”). Additionally, the rates established by the September 2016 Order will be used prospectively from the date of that order until a new approved rate is established by the FERC in ruling on the Second Complaint described below, resulting in an ROE used currently by ITCTransmission, METC and ITC Midwest of 11.35%, 11.35% and 11.32%, respectively. The September 2016 Order requires all MISO TOs, including our MISO Regulated Operating Subsidiaries, to provide refunds within 30 days for the Initial Refund Period. The estimated refund for the Initial Complaint resulting from this FERC order, including interest, is $118 million for our MISO Regulated Operating Subsidiaries, recorded in current liabilities on the consolidated statements of financial position. On October 21, 2016, the MISO TOs, including our MISO Regulated Operating Subsidiaries, filed a request with the FERC for an extension of nine months, until July 28, 2017, to provide refunds, which was granted by the FERC on October 28, 2016. Additionally, on October 28, 2016, the MISO TOs, including our MISO Regulated Operating Subsidiaries, filed a request with the FERC for rehearing of the September 2016 Order regarding the future exclusion of certain short-term growth projections in the two-step DCF analysis used by FERC to determine the cost of equity of public utilities. On October 28, 2016, the complainants also filed a request with the FERC for rehearing, citing that FERC erred in several material respects in the September 2016 Order. The FERC issued a tolling order on November 28, 2016 to allow for additional time to address the rehearing requests. On February 14, 2017, our MISO Regulated Operating Subsidiaries provided $119 million to MISO to fund the payment of the refund, including interest, pursuant to the September 2016 Order.
On February 12, 2015, an additional complaint was filed with the FERC under Section 206 of the FPA (the “Second Complaint”) by separate complainants, seeking a FERC order to reduce the base ROE used in the formula transmission rates of our MISO Regulated Operating Subsidiaries to 8.67%, with an effective date of February 12, 2015. On June 18, 2015, the FERC set the Second Complaint for hearing and settlement procedures. The FERC also set the refund effective date for the Second Complaint as February 12, 2015.
On June 30, 2016, the presiding administrative law judge issued an initial decision on the Second Complaint, which recommended a base ROE of 9.70% for February 12, 2015 through May 11, 2016 (the “Second Refund Period”), with a maximum ROE of 10.68%. The initial decision is a non-binding recommendation to the FERC on the Second Complaint, and all parties, including the MISO TOs and the complainants, have filed briefs contesting various parts of the proposed findings and recommendations. In resolving the Second Complaint, we expect the FERC to establish a new base ROE and zone of reasonable returns that will be used, along with any ROE adders, to calculate the refund liability for the Second Refund Period. We anticipate a FERC order on the Second Complaint in 2017. The timing of providing refunds for the Second Complaint is uncertain; however, we do not expect to provide refunds during 2017 for the Second Complaint and therefore, the associated refund liability is recorded in non-current liabilities on the consolidated statements of financial position.


31

In addition to the estimated refund for the Initial Complaint noted above, we believe it is probable that a refund will be required in connection with the Second Complaint. As of December 31, 2016, the estimated range of aggregate refunds for the Initial Refund Period and Second Refund Period is expected to be from $221 million to $258 million on a pre-tax basis. As of December 31, 2016, our MISO Regulated Operating Subsidiaries had recorded aggregate estimated regulatory liabilities totaling $258 million for the Initial Complaint and Second Complaint, representing the best estimate of the probable aggregate refunds based on the resolution of the Initial Complaint in the September 2016 Order. As of December 31, 2015, our MISO Regulated Operating Subsidiaries had recorded an aggregate estimated regulatory liability of $168 million, which represented the low end of the range of potential refunds as of that date, as there was no best estimate within the range of refunds at that time. The recognition of these estimated liabilities resulted in the following impacts to our consolidated results of operations:
 
Year Ended December 31,
(In millions)
2016
 
2015
 
2014
Increase (decrease) in:
 
 
 
 
 
Operating revenues
$
(80
)
 
$
(115
)
 
$
(47
)
Interest expense
10

 
5

 
1

Estimated net income
(55
)
 
(73
)
 
(29
)
It is possible the outcome of these matters could differ from the estimated range of losses and materially affect our consolidated results of operations due to the uncertainty of the calculation of an authorized base ROE along with the zone of reasonableness under the newly adopted two-step DCF methodology, which is subject to significant discretion by the FERC. As of December 31, 2016, our MISO Regulated Operating Subsidiaries had a total of approximately $3 billion of equity in their collective capital structures for ratemaking purposes. Based on this level of aggregate equity, we estimate that each 10 basis point reduction in the authorized ROE would reduce annual consolidated net income by approximately $3 million.
In a separate but related matter, in November 2014, METC, ITC Midwest and other MISO TOs filed a request with the FERC, under FPA Section 205, for authority to include a 50 basis point incentive adder for RTO participation in each of the TOs’ formula rates. On January 5, 2015, the FERC approved the use of this incentive adder, effective January 6, 2015. Additionally, ITC Midwest filed a request with the FERC, under FPA Section 205, in January 2015 for authority to include a 100 basis point incentive adder for independent transmission ownership, which is currently authorized for ITCTransmission and METC. On March 31, 2015, the FERC approved the use of a 50 basis point incentive adder for independence, effective April 1, 2015. On April 30, 2015, ITC Midwest filed a request with the FERC for rehearing on the approved incentive adder for independence and this request was subsequently denied by the FERC on January 6, 2016. An appeal of the FERC’s decision has been filed. Beginning September 28, 2016, these incentive adders have been applied to METC’s and ITC Midwest’s base ROEs in establishing their total authorized ROE rates, subject to the maximum ROE limitation in the September 2016 Order of 11.35%.
MISO Formula Rate Template Modifications Filing
On October 30, 2015, our MISO Regulated Operating Subsidiaries requested modifications, pursuant to Section 205 of the FPA, to certain aspects of their respective formula rate templates which included, among other things, changes to ensure that various income tax items are computed correctly for purposes of determining their revenue requirements. Our MISO Regulated Operating Subsidiaries requested an effective date of January 1, 2016 for the proposed template changes. On December 30, 2015, the FERC conditionally accepted the formula rate template modifications and required a further compliance filing, which was made on February 8, 2016. On April 14, 2016, the FERC issued an order accepting the February 8, 2016 compliance filing, effective January 1, 2016. The formula rate templates, prior to any proposed modifications, include certain deferred income taxes on contributions in aid of construction in rate base that resulted in the recovery of excess amounts from customers. As of December 31, 2016 and 2015, our MISO Regulated Operating Subsidiaries had recorded an aggregate refund liability of $2 million and $10 million, respectively. The initial recognition of this refund liability in 2015 resulted in a reduction to operating revenues and an increase to interest expense during the year ended December 31, 2015.
Challenges Regarding Bonus Depreciation
On December 18, 2015, IP&L filed a formal challenge (“IP&L challenge”) with the FERC against ITC Midwest on certain inputs to ITC Midwest’s formula rates. The IP&L challenge alleged that ITC Midwest has unreasonably and imprudently opted out of using bonus depreciation in the calculation of its federal income tax expense and thereby unduly increased the transmission charges for transmission service to customers. On March 11, 2016,


32

the FERC granted the IP&L challenge in part by requiring ITC Midwest to recalculate its revenue requirements, effective January 1, 2015, to simulate the election of bonus depreciation for 2015. The FERC denied IP&L’s request that ITC Midwest be required to elect bonus depreciation in any past or future years; however, stakeholders will be able to challenge any decision by ITC Midwest not to take bonus depreciation in future years. On June 8, 2016, the FERC denied ITC Midwest’s request for rehearing of the March 11, 2016 order. On August 3, 2016, ITC Midwest filed a petition for review of the FERC’s March 11, 2016 and June 8, 2016 orders in the United States Court of Appeals, District of Columbia Circuit. On September 8, 2016, ITC Midwest filed a motion to defer the petition pending the resolution of a private letter ruling matter from the IRS. In a separate but related matter, on April 15, 2016, Consumers Energy filed a formal challenge, or in the alternative, a complaint under Section 206 of the FPA, with the FERC against METC relating to METC’s historical practice of opting out of using bonus depreciation. On July 8, 2016, the FERC denied Consumers Energy’s formal challenge and dismissed the complaint without prejudice.
The consolidated financial statements reflect the election of bonus depreciation for tax years 2015 and 2016 and the corresponding effects on 2016 revenue requirements for our Regulated Operating Subsidiaries. Additionally, as required by the March 11, 2016 FERC order, we have simulated the election of bonus depreciation for ITC Midwest’s 2015 revenue requirement and included the impact of the corresponding refund obligation in these consolidated financial statements. The total impact from reflecting the election of bonus depreciation as described above was lower revenues of $20 million and lower net income of approximately $12 million for the year ended December 31, 2016 as compared to the same period if bonus depreciation was not reflected. These matters also resulted in additional net deferred income tax liabilities of approximately $109 million and a corresponding income tax receivable of $12 million as of December 31, 2016, and income tax refunds of $128 million, which were received from the Internal Revenue Service (“IRS”) in August 2016. We are unable to predict the final outcome of this matter; however, the election of bonus depreciation will result in higher cash flows in the year of the election and/or subsequent periods, and reduce our rate base and therefore decrease our revenues and net income over the tax lives of the eligible assets. Bonus depreciation is currently available for property acquired and placed in service through 2019, with certain provisions that allow for an additional year of eligibility for certain property with long construction periods. If bonus depreciation is elected for a given year, we estimate that, based on an amount of tax additions that may be eligible for bonus depreciation representative of our investment plans in the near term, the higher deferred tax liabilities and the corresponding reduced rate base could reduce revenues recognized by us initially for that year by $15 million to $20 million, with a corresponding reduction to annual net income of $9 million to $12 million (disregarding any favorable effects from the use of the potential cash tax savings), with the negative effect on annual revenues and net income relating to each year’s election decreasing each year over the tax lives of the assets.
Significant Components of Results of Operations
Revenues
We derive nearly all of our revenues from providing transmission, scheduling, control and dispatch services and other related services over our Regulated Operating Subsidiaries’ transmission systems to DTE Electric, Consumers Energy, IP&L and other entities, such as alternative electricity suppliers, power marketers and other wholesale customers that provide electricity to end-use consumers, as well as from transaction-based capacity reservations on our transmission systems. MISO and SPP are responsible for billing and collecting the majority of transmission service revenues. As the billing agent for our MISO Regulated Operating Subsidiaries and ITC Great Plains, MISO and SPP collect fees for the use of our transmission systems, invoicing DTE Electric, Consumers Energy, IP&L and other customers on a monthly basis.
Network Revenues are generated from network customers for their use of our electric transmission systems and are based on the actual revenue requirements as a result of our accounting under our cost-based formula rates that contain a true-up mechanism. Refer to “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates — Revenue Recognition under Cost-Based Formula Rates with True-Up Mechanism” for a discussion of revenue recognition relating to network revenues.
Network revenues from ITC Great Plains include the annual revenue requirements specific to projects that are charged exclusively within one pricing zone within SPP or are classified as direct assigned network upgrades under the SPP tariff, and contain a true-up mechanism.


33

Point-to-Point Revenues consist of revenues generated from a type of transmission service for which the customer pays for transmission capacity reserved along a specified path between two points on an hourly, daily, weekly or monthly basis. Point-to-point revenues also include other components pursuant to schedules under the MISO and SPP transmission tariffs. Point-to-point revenues are treated as a revenue credit to network or regional customers and are a reduction to gross revenue requirement when calculating net revenue requirement under our cost-based formula rates.
Regional Cost Sharing Revenues are generated from transmission customers throughout RTO regions for their use of our MISO Regulated Operating Subsidiaries’ network upgrade projects that are eligible for regional cost sharing under provisions of the MISO tariff, including MVP projects such as the four North Central MVPs and the Thumb Loop Project in Michigan. Regional cost sharing revenue also includes revenues collected by transmission customers from other RTOs outside of MISO to allocate costs of certain transmission plant investments. Additionally, certain projects at ITC Great Plains are eligible for recovery through a region-wide charge under provisions of the SPP tariff. A portion of regional cost sharing revenues is treated as a revenue credit to regional or network customers and is a reduction to gross revenue requirement when calculating net revenue requirement under our cost-based formula rates.
Scheduling, Control and Dispatch Revenues are allocated to our MISO Regulated Operating Subsidiaries by MISO as compensation for the services performed in operating the transmission system. Such services include monitoring of reliability data, current and next day analysis, implementation of emergency procedures and outage coordination and switching.
Other Revenues consist of rental revenues, easement revenues, revenues relating to utilization of jointly owned assets under our transmission ownership and operating agreements and amounts from providing ancillary services to customers. The majority of other revenues are treated as a revenue credit and taken as a reduction to gross revenue requirement when calculating net revenue requirement under our cost-based formula rates.
Operating Expenses
Operation and Maintenance Expenses consist primarily of the costs for contractors that operate and maintain our transmission systems as well as our personnel involved in operation and maintenance activities.
Operation expenses include activities related to control area operations, which involve balancing loads and generation and transmission system operations activities, including monitoring the status of our transmission lines and stations. Rental expenses relating to land easements, including METC’s Easement Agreement, are also recorded within operation expenses.
Maintenance expenses include preventive or planned maintenance, such as vegetation management, tower painting and equipment inspections, as well as reactive maintenance for equipment failures.
General and Administrative Expenses consist primarily of costs for personnel in our legal, information technology, finance, regulatory, human resources and business development organizations, general office expenses and fees for professional services. Professional services are principally composed of outside legal, consulting, audit and information technology services.
Depreciation and Amortization Expenses consist primarily of depreciation of property, plant and equipment using the straight-line method of accounting. Additionally, this consists of amortization of various regulatory and intangible assets.
Taxes Other than Income Taxes consist primarily of property taxes and payroll taxes.
Other Items of Income or Expense
Interest Expense consists primarily of interest on debt at ITC Holdings and our Regulated Operating Subsidiaries. Additionally, the amortization of debt financing expenses is recorded to interest expense. An allowance for borrowed funds used during construction is included in property, plant and equipment accounts and treated as a reduction to interest expense. The amortization of gains and losses on settled and terminated derivative financial instruments is also recorded to interest expense.
Allowance for Equity Funds Used During Construction (“AFUDC equity”) is recorded as an item of other income and is included in property, plant and equipment accounts. The allowance represents a return on equity at our Regulated Operating Subsidiaries used for construction purposes in accordance with the FERC regulations.


34

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)
2016
 
2015
 
(Decrease)
 
(Decrease)
 
2014
 
(Decrease)
 
(Decrease)
OPERATING REVENUES
$
1,125

 
$
1,045

 
$
80

 
8%
 
$
1,023

 
$
22

 
2%
OPERATING EXPENSES
 
 
 
 
 
 
 
 
 
 
 
 
 
Operation and maintenance
114

 
113

 
1

 
1%
 
112

 
1

 
1%
General and administrative
239

 
145

 
94

 
65%
 
115

 
30

 
26%
Depreciation and amortization
158

 
145

 
13

 
9%
 
128

 
17

 
13%
Taxes other than income taxes
93

 
82

 
11

 
13%
 
76

 
6

 
8%
Other operating income and expenses — net
(1
)
 
(1
)
 
—

 
—%
 
(1
)
 
—

 
—%
Total operating expenses
603

 
484

 
119

 
25%
 
430

 
54

 
13%
OPERATING INCOME
522

 
561

 
(39
)
 
(7)%
 
593

 
(32
)
 
(5)%
OTHER EXPENSES (INCOME)
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest expense — net
211

 
204

 
7

 
3%
 
187

 
17

 
9%
Allowance for equity funds used during construction
(35
)
 
(28
)
 
(7
)
 
25%
 
(21
)
 
(7
)
 
33%
Loss on extinguishment of debt
—

 
—

 
—

 
n/a
 
29

 
(29
)
 
(100)%
Other income
(2
)
 
(2
)
 
—

 
—%
 
(1
)
 
(1
)
 
100%
Other expense
5

 
3

 
2

 
67%
 
5

 
(2
)
 
(40)%
Total other expenses (income)
179

 
177

 
2

 
1%
 
199

 
(22
)
 
(11)%
INCOME BEFORE INCOME TAXES
343

 
384

 
(41
)
 
(11)%
 
394

 
(10
)
 
(3)%
INCOME TAX PROVISION
97

 
142

 
(45
)
 
(32)%
 
150

 
(8
)
 
(5)%
NET INCOME
$
246

 
$
242

 
$
4

 
2%
 
$
244

 
$
(2
)
 
(1)%
Operating Revenues
Year ended December 31, 2016 compared to year ended December 31, 2015
The following table sets forth the components of and changes in operating revenues:
 
 
 
 
 
 
 
 
 
 
 
Percentage
 
2016
 
2015
 
Increase
 
Increase
(In millions)
Amount
 
Percentage
 
Amount
 
Percentage
 
(Decrease)
 
(Decrease)
Network revenues
$
814

 
72
 %
 
$
802

 
77
 %
 
$
12

 
1
 %
Regional cost sharing revenues
337

 
30
 %
 
328

 
31
 %
 
9

 
3
 %
Point-to-point
20

 
2
 %
 
15

 
2
 %
 
5

 
33
 %
Scheduling, control and dispatch
14

 
1
 %
 
13

 
1
 %
 
1

 
8
 %
Other
20

 
2
 %
 
12

 
1
 %
 
8

 
67
 %
Recognition of refund liabilities
(80
)
 
(7
)%
 
(125
)
 
(12
)%
 
45

 
(36
)%
Total
$
1,125

 
100
 %
 
$
1,045

 
100
 %
 
$
80

 
8
 %
Network revenues increased due primarily to higher net revenue requirements at our Regulated Operating Subsidiaries, partially offset by higher regional revenue requirements, during the year ended December 31, 2016 as compared to 2015. Higher net revenue requirements were due primarily to higher rate bases associated with higher balances of property, plant and equipment in-service in 2016.


35

Regional cost sharing revenues increased primarily due to additional capital projects identified by MISO and SPP as eligible for regional cost sharing and these projects being placed in-service, in addition to higher accumulated investment for regional cost sharing projects in northern Michigan and Kansas during the year ended December 31, 2016 as compared to the same period in 2015.
The recognition of the liabilities for the refund relating to the formula rate template modifications and the refund and potential refund relating to the ROE complaints, described in Notes 5 and 15 to the consolidated financial statements, respectively, resulted in a reduction to operating revenues of $80 million and $125 million during the years ended December 31, 2016 and 2015, respectively. We are not able to estimate whether any required refunds would be applied to all components of revenue listed in the table above or only certain components.
Operating revenues for the years ended December 31, 2016 and 2015 include revenue accruals and deferrals as described in Note 5 to the consolidated financial statements.
Year ended December 31, 2015 compared to year ended December 31, 2014
The following table sets forth the components of and changes in operating revenues:
 
 
 
 
 
 
 
 
 
 
 
Percentage
 
2015
 
2014
 
Increase
 
Increase
(In millions)
Amount
 
Percentage
 
Amount
 
Percentage
 
(Decrease)
 
(Decrease)
Network revenues
$
802

 
77
 %
 
$
764

 
75
 %
 
$
38

 
5
 %
Regional cost sharing revenues
328

 
31
 %
 
265

 
26
 %
 
63

 
24
 %
Point-to-point
15

 
2
 %
 
18

 
2
 %
 
(3
)
 
(17
)%
Scheduling, control and dispatch
13

 
1
 %
 
12

 
1
 %
 
1

 
8
 %
Other
12

 
1
 %
 
11

 
1
 %
 
1

 
9
 %
Recognition of refund liabilities
(125
)
 
(12
)%
 
(47
)
 
(5
)%
 
(78
)
 
166
 %
Total
$
1,045

 
100
 %
 
$
1,023

 
100
 %
 
$
22

 
2
 %
Network revenues increased due primarily to higher net revenue requirements at our Regulated Operating Subsidiaries, partially offset by higher regional revenue requirements, during the year ended December 31, 2015 as compared to 2014. Higher net revenue requirements were due primarily to higher rate bases associated with higher balances of property, plant and equipment in-service in 2015.
Regional cost sharing revenues increased primarily due to additional capital projects identified by MISO and SPP as eligible for regional cost sharing and these projects being placed in-service, in addition to higher accumulated investment for regional cost sharing projects in northern Michigan and Kansas during the year ended December 31, 2015 as compared to the same period in 2014. We expect to continue to receive regional cost sharing revenues and the amounts could increase in the near future, including revenues associated with projects that have been or are expected to be approved for regional cost sharing.
The recognition of the liabilities for the refund relating to the formula rate template modifications and the refund and potential refund relating to the ROE complaints described in Notes 5 and 15 to the consolidated financial statements, respectively, resulted in a reduction to operating revenues totaling $125 million and $47 million during the years ended December 31, 2015 and 2014, respectively. We are not able to estimate whether any required refunds would be applied to all components of revenue listed in the table above or only certain components.
Operating revenues for the years ended December 31, 2015 and 2014 include revenue accruals and deferrals as described in Note 5 to the consolidated financial statements.
Operating Expenses
Operation and maintenance expenses
Year ended December 31, 2016 and 2015 compared to year ended December 31, 2015 and 2014, respectively
Operation and maintenance expenses were consistent with the respective prior period.


36

General and administrative expenses
Year ended December 31, 2016 compared to year ended December 31, 2015
General and administrative expenses increased $59 million related to higher compensation-related expenses due to retention bonuses relating to the Merger, personnel additions and additional stock compensation expense, including approximately $41 million due to the accelerated vesting of the share-based awards that occurred at the completion of the Merger as described in Note 13 to the consolidated financial statements, and increased $55 million due primarily to the external legal, advisory and financial services fees incurred in 2016 related to the Merger. These increases were partially offset by a decrease of $10 million in development bonus expenses as described above under “Recent Developments — Development Bonuses.”
Year ended December 31, 2015 compared to year ended December 31, 2014
General and administrative expenses increased due primarily to higher compensation-related expenses of $17 million, mainly due to $8 million additional development bonuses described above under “Recent Developments — Development Bonuses” and $10 million higher professional services such as legal and advisory services fees primarily for various development initiatives.
Depreciation and amortization expenses
Year ended December 31, 2016 and 2015 compared to year ended December 31, 2015 and 2014, respectively
Depreciation and amortization expenses increased in the respective period due primarily to a higher depreciable base resulting from property, plant and equipment in-service additions.
Taxes other than income taxes
Year ended December 31, 2016 compared to year ended December 31, 2015
Taxes other than income taxes increased due to higher property tax expenses primarily due to our Regulated Operating Subsidiaries’ 2015 capital additions, which are included in the assessments for 2016 property taxes.
Year ended December 31, 2015 compared to year ended December 31, 2014
Taxes other than income taxes increased due to higher property tax expenses primarily due to our Regulated Operating Subsidiaries’ 2014 capital additions, which are included in the assessments for 2015 property taxes.
Other expenses (income)
Year ended December 31, 2016 compared to year ended December 31, 2015
Interest expense increased due primarily to the additional interest expense associated with the refund liability relating to the ROE complaints described in Note 15 to the consolidated financial statements and long-term debt issuances subsequent to December 31, 2015, which were used for refinancing of current debt maturities and general corporate purposes.
AFUDC equity increased due primarily to higher balances of construction work in progress eligible for AFUDC equity during the period.
Year ended December 31, 2015 compared to year ended December 31, 2014
Interest expense increased due primarily to additional interest expense associated with the net issuance of $300 million in long-term debt securities subsequent to September 30, 2014 and the refund liabilities described in Notes 5 and 15 to the consolidated financial statements. These increases were partially offset by an increase in the allowance for borrowed funds used during construction (“AFUDC debt”), which is a reduction to interest expense, due primarily to higher balances of construction work in progress eligible for AFUDC debt during the period.
AFUDC equity increased due primarily to higher balances of construction work in progress eligible for AFUDC equity during the period.
The loss on extinguishment of debt represents the tender premium, the write-off of deferred debt issuance costs and other related expenses associated with the partial tender and retirement in 2014 of $116 million of the 5.875% ITC Holdings Senior Notes and $55 million of the 6.375% ITC Holdings Senior Notes.


37

Income Tax Provision
Year ended December 31, 2016 compared to year ended December 31, 2015
Our effective tax rates for the years ended December 31, 2016 and 2015 are 28.3% and 36.9%, respectively. Our effective tax rate as of December 31, 2016 was less than our 35% statutory federal income tax rate due primarily to us recognizing an income tax benefit of $27 million for excess tax deductions for the year ended December 31, 2016 as a result of adopting the new accounting guidance associated with share-based payments as described in Notes 3 and 10. Our effective tax rate as of December 31, 2015 exceeded our 35% statutory federal income tax rate due primarily to state income taxes, partially offset by the tax effects of AFUDC equity. The amount of income tax expense relating to AFUDC equity was recognized as a regulatory asset and not included in the income tax provision.
Year ended December 31, 2015 compared to year ended December 31, 2014
Our effective tax rates for the years ended December 31, 2015 and 2014 are 36.9% and 38.1%, respectively. Our effective tax rate in both periods exceeded our 35% statutory federal income tax rate due primarily to state income taxes, partially offset by the tax effects of AFUDC equity. The amount of income tax expense relating to AFUDC equity was recognized as a regulatory asset and not included in the income tax provision.
Liquidity and Capital Resources
We expect to maintain our approach to fund our future capital requirements with cash from operations at our Regulated Operating Subsidiaries, our existing cash and cash equivalents, issuances under our commercial paper program and amounts available under our revolving credit agreements (the terms of which are described in Note 9 to the consolidated financial statements). In addition, we may from time to time secure debt funding in the capital markets, although we can provide no assurance that we will be able to obtain financing on favorable terms or at all. As market conditions warrant, we may also from time to time repurchase debt securities issued by us, in the open market, in privately negotiated transactions, by tender offer or otherwise. We expect that our capital requirements will arise principally from our need to:
•
Fund capital expenditures at our Regulated Operating Subsidiaries. Our plans with regard to property, plant and equipment investments are described in detail above under “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Investment and Operating Results Trends.”
•
Fund business development expenses and related capital expenditures. We are pursuing development activities for transmission projects that will continue to result in the incurrence of development expenses and could result in significant capital expenditures.
•
Fund working capital requirements.
•
Fund our debt service requirements, including principal repayments and periodic interest payments, which are further described in detail below under “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Contractual Obligations.” We expect our interest payments to increase each year as a result of additional debt expected to be incurred to fund our capital expenditures and for general corporate purposes.
•
Fund any refund obligation in connection with the return on equity complaints.
•
Fund contributions to our retirement benefit plans, as described in Note 11 to the consolidated financial statements. We expect to contribute up to $12 million to these plans in 2017.
In addition to the expected capital requirements above, any adverse determinations relating to the regulatory matters or contingencies described in Notes 5 and 15 to the consolidated financial statements would result in additional capital requirements.
We believe that we have sufficient capital resources to meet our currently anticipated short-term needs. We rely on both internal and external sources of liquidity to provide working capital and fund capital investments. ITC Holdings’ sources of cash are dividends and other payments received by us from our Regulated Operating Subsidiaries and any of our other subsidiaries as well as the proceeds raised from the sale of our debt securities. Each of our Regulated Operating Subsidiaries, while wholly owned by ITC Holdings, is legally distinct from ITC Holdings and has no obligation, contingent or otherwise, to make funds available to us.


38

We expect to continue to utilize our commercial paper program and revolving credit agreements as well as our cash and cash equivalents as needed to meet our short-term cash requirements. As of December 31, 2016, we had consolidated indebtedness under our revolving credit agreements of $334 million, with unused capacity under the revolving credit agreements of $666 million. Additionally, ITC Holdings had $145 million of commercial paper issued and outstanding as of December 31, 2016, with the ability to issue an additional $255 million under the commercial paper program. See Note 9 to the consolidated financial statements for a detailed discussion of the commercial paper program and our revolving credit agreements as well as the debt activity during the years ended December 31, 2016 and 2015.
As of December 31, 2016, we had approximately $90 million of fixed rate debt maturing within one year and a refund obligation of $118 million in connection with the September 2016 Order, which we expect to (1) repay with either borrowings under our revolving credit agreements or commercial paper issued under ITC Holdings’ commercial paper program, or (2) refinance with long-term debt. To address our long-term capital requirements, we expect that we will need to obtain additional debt financing. Certain of our capital projects could be delayed if we experience difficulties in accessing capital. We expect to be able to obtain such additional financing as needed, in amounts and upon terms that will be reasonably satisfactory to us due to our strong credit ratings and our historical ability to obtain financing.
Credit Ratings
Credit ratings by nationally recognized statistical rating agencies are an important component of our liquidity profile. Credit ratings relate to our ability to issue debt securities and the cost to borrow money, and should not be viewed as recommendation to buy, sell or hold securities. Ratings are subject to revision or withdrawal at any time and each rating should be evaluated independently of any other rating. Our current credit ratings are displayed in the following table. An explanation of these ratings may be obtained from the respective rating agency.
 
 
 
 
Standard and Poor’s
 
Moody’s Investor
Issuer
 
Issuance
 
Ratings Services (a)
 
Service, Inc. (b)
ITC Holdings
 
Senior Unsecured Notes
 
BBB+
 
Baa2
ITC Holdings
 
Commercial Paper
 
A-2
 
Prime-2
ITCTransmission
 
First Mortgage Bonds
 
A
 
A1
METC
 
Senior Secured Notes
 
A
 
A1
ITC Midwest
 
First Mortgage Bonds
 
A
 
A1
ITC Great Plains
 
First Mortgage Bonds
 
A
 
A1
____________________________
(a)
On June 8, 2015, Standard and Poor’s Ratings Services (“Standard and Poor’s”) assigned a short-term issuer credit rating to ITC Holdings, which applies to the commercial paper program discussed in Note 9 to the consolidated financial statements. Additionally, on October 18, 2016, Standard and Poor’s reaffirmed the senior unsecured credit rating of ITC Holdings and the secured credit ratings of our MISO Regulated Operating Subsidiaries and ITC Great Plains as well as revised the outlook of the issuer credit ratings of these particular entities to stable from negative, subsequent to the completion of the Merger. Refer to Note 2 to the consolidated financial statements for details on the Merger.
(b)
On June 9, 2015, Moody’s Investor Service, Inc. (“Moody’s”) assigned a short-term commercial paper rating to ITC Holdings, which applies to the commercial paper program discussed in Note 9 to the consolidated financial statements. Additionally, on April 15, 2016, Moody’s reaffirmed the credit ratings for the associated debt for ITC Holdings, ITCTransmission, ITC Midwest and ITC Great Plains. On April 26, 2016, Moody’s assigned a senior secured rating to METC’s 3.90% Senior Secured Note issuance described in Note 9 to the consolidated financial statements. All of the credit ratings have a stable outlook.
Covenants
Our debt instruments contain numerous financial and operating covenants that place significant restrictions on certain transactions as well as require us to meet certain financial ratios, which are described in Note 9 to the consolidated financial statements. As of December 31, 2016, we were not in violation of any debt covenant. In the event of a downgrade in our credit ratings, none of the covenants would be directly impacted, although the borrowing costs under our revolving credit agreements would increase.


39

Cash Flows
The following table summarizes cash flows for the periods indicated:
 
Year Ended December 31,
(In millions)
2016
 
2015
 
2014
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
 
 
Net income
$
246

 
$
242

 
$
244

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
 
Depreciation and amortization expense
158

 
145

 
128

Recognition, refund and collection of revenue accruals and deferrals — including accrued interest
(2
)
 
(54
)
 
(4
)
Deferred income tax expense
219

 
77

 
90

Other
66

 
146

 
44

Net cash provided by operating activities
687

 
556

 
502

CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
 
 
Expenditures for property, plant and equipment
(750
)
 
(701
)
 
(753
)
Other
15

 
1

 
18

Net cash used in investing activities
(735
)
 
(700
)
 
(735
)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
 
 
Net issuance/repayment of debt (including commercial paper and revolving and term loan credit agreements)
161

 
352

 
463

Issuance of common stock
13

 
14

 
21

Dividends on common and restricted stock
(90
)
 
(108
)
 
(96
)
Dividends to Investment Holdings
(33
)
 
—

 
—

Refundable deposits from and repayments to generators for transmission network upgrades — net
23

 
1

 
(23
)
Repurchase and retirement of common stock
(9
)
 
(137
)
 
(134
)
Settlement of share-based awards associated with the Merger
(137
)
 
—

 
—

Contribution from Investment Holdings associated with the settlement of share-based awards
137

 
—

 
—

Other
(23
)
 
8

 
(4
)
Net cash provided by financing activities
42

 
130

 
227

NET DECREASE IN CASH AND CASH EQUIVALENTS
(6
)
 
(14
)
 
(6
)
CASH AND CASH EQUIVALENTS — Beginning of period
14

 
28

 
34

CASH AND CASH EQUIVALENTS — End of period
$
8

 
$
14

 
$
28

Cash Flows From Operating Activities
Year ended December 31, 2016 compared to year ended December 31, 2015
Net cash provided by operating activities increased $131 million in 2016 compared to 2015. The increase in cash provided by operating activities was due primarily to receipt of the federal income tax refund of $128 million in August 2016 and lower income taxes paid of $33 million during 2016 compared to 2015, which both resulted from the election of bonus depreciation as described in Note 5 to the consolidated financial statements. Additionally, the cash received from operating revenues increased by $67 million during 2016 compared to 2015. These increases were partially offset by an increase in payments of operating expenses of $54 million and the regional cost allocation refund of $29 million provided by ITCTransmission to the relevant RTOs in October 2016 as described in Note 5 to the consolidated financial statements.
Year ended December 31, 2015 compared to year ended December 31, 2014
Net cash provided by operating activities increased $54 million in 2015 compared to 2014. The increase in cash provided by operating activities was due primarily to an increase in cash received from operating revenues of $70 million during 2015 compared to 2014. This increase was partially offset by an increase in payments of operating expenses of $25 million.


40

Cash Flows From Investing Activities
Year ended December 31, 2016 compared to year ended December 31, 2015
Net cash used in investing activities increased $35 million in 2016 compared to 2015. The increase in cash used in investing activities was due primarily to the timing of payments for investments in property, plant and equipment during the year ended December 31, 2016 compared to the same period in 2015.
Year ended December 31, 2015 compared to year ended December 31, 2014
Net cash used in investing activities decreased $35 million in 2015 compared to 2014. The decrease in cash used in investing activities was due primarily to the timing of payments for investments in property, plant and equipment during the year ended December 31, 2015 compared to the same period in 2014.
Cash Flows From Financing Activities
Year ended December 31, 2016 compared to year ended December 31, 2015
Net cash provided by financing activities decreased $88 million in 2016 compared to 2015. The decrease in cash provided by financing activities was due primarily to a net decrease of $554 million in amounts outstanding under our revolving and term loan credit agreements, the settlement of share-based awards associated with the Merger of $137 million, a decrease of $47 million in net issuances of commercial paper under our commercial paper program and an increase in dividend payments of $15 million during 2016 compared to 2015. These decreases were partially offset by an increase in long-term debt issuances of $374 million, a capital contribution from Investments Holdings of $137 million, a decrease in the repurchase and retirement of common stock of $128 million, a decrease in payments of $36 million to retire long-term debt and higher net proceeds of $22 million associated with refundable deposits for transmission network upgrades. Additionally, during the year ended December 31, 2015, we paid $115 million in connection with an accelerated share repurchase program. See Note 9 to the consolidated financial statements on the issuances and retirement of long-term debt.
Year ended December 31, 2015 compared to year ended December 31, 2014
Net cash provided by financing activities decreased $97 million in 2015 compared to 2014. The decrease in cash provided by financing activities was due primarily to a decrease in long-term debt issuances of $574 million during 2015 compared to 2014. This decrease was partially offset by a net increase of $245 million in amounts outstanding under our revolving and term loan credit agreements, a decrease in payments of $124 million to retire long-term debt, the $95 million in net proceeds from the issuance of commercial paper under our commercial paper program during the year ended December 31, 2015 and lower net payments of $24 million associated with refundable deposits for transmission network upgrades. See Note 9 to the consolidated financial statements for detail on the issuances and retirements of debt.


41

Contractual Obligations
The following table details our contractual obligations as of December 31, 2016:
 
 
 
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
$
2,185

 
$
50

 
$
385

 
$
200

 
$
1,550

ITC Holdings revolving credit agreement
73

 
—

 
73

 
—

 
—

ITC Holdings commercial paper program
145

 
145

 
—

 
—

 
—

ITCTransmission First Mortgage Bonds
585

 
—

 
100

 
—

 
485

ITCTransmission revolving credit agreement
44

 
—

 
44

 
—

 
—

METC Senior Secured Notes
475

 
—

 
—

 
—

 
475

METC revolving credit agreement
31

 
—

 
31

 
—

 
—

ITC Midwest First Mortgage Bonds
750

 
40

 
—

 
35

 
675

ITC Midwest revolving credit agreement
127

 
—

 
127

 
—

 
—

ITC Great Plains First Mortgage Bonds
150

 
—

 
—

 
—

 
150

ITC Great Plains revolving credit agreement
59

 
—

 
59

 
—

 
—

Interest payments:
 
 
 
 
 
 
 
 
 
ITC Holdings Senior Notes
1,033

 
103

 
157

 
133

 
640

ITCTransmission First Mortgage Bonds
593

 
29

 
49

 
47

 
468

METC Senior Secured Notes
547

 
20

 
40

 
40

 
447

ITC Midwest First Mortgage Bonds
736

 
32

 
66

 
63

 
575

ITC Great Plains First Mortgage Bonds
174

 
6

 
12

 
13

 
143

Operating leases
5

 
1

 
2

 
2

 
—

Purchase obligations
44

 
43

 
1

 
—

 
—

Regulatory liabilities — revenue deferrals, including accrued interest
41

 
9

 
32

 
—

 
—

Regulatory liabilities — refund related to the formula rate template modifications, including accrued interest
2

 
2

 
—

 
—

 
—

Regulatory liabilities — refund related to the Initial Complaint, including accrued interest
118

 
118

 
—

 
—

 
—

METC Easement Agreement
339

 
10

 
20

 
20

 
289

Other
1

 
1

 
—

 
—

 
—

Total obligations
$
8,257

 
$
609

 
$
1,198

 
$
553

 
$
5,897

Interest payments included above relate only to our fixed-rate long-term debt outstanding at December 31, 2016. We also expect to pay interest and commitment fees under our variable-rate revolving credit agreements that have not been included above due to varying amounts of borrowings and interest rates under the facilities. In 2016, we paid $5 million of interest and commitment fees under our revolving credit agreements.
Operating leases include leases for office space, equipment and storage facilities. Purchase obligations represent commitments primarily for materials, services and equipment that had not been received as of December 31, 2016, primarily for construction and maintenance projects for which we have an executed contract. The majority of the items relate to materials and equipment that have long production lead times. See Note 15 to the consolidated financial statement for more information on our operating leases and purchases obligations.
The revenue deferrals, including accrued interest, in the table above represent the over-recovery of revenues resulting from differences between the amounts billed to customers and actual revenue requirement at each of our Regulated Operating Subsidiaries, as described in Note 5 to the consolidated financial statements. These amounts will offset future revenue requirement for purposes of calculating our formula rates as part of the true-up mechanism in our rate construct.


42

See Notes 5 and 15 to the consolidated financial statements for information on the refund related to the formula rate template modifications, including accrued interest, and the refund related to the Initial Complaint, including accrued interest, respectively. On February 14, 2017, our MISO Regulated Operating Subsidiaries provided $119 million to MISO to fund the payment of the refund, including interest, pursuant to the September 2016 Order.
The Easement Agreement provides METC with an easement for transmission purposes and rights-of-way, leasehold interests, fee interests and licenses associated with the land over which the transmission lines cross. The cost for use of the rights-of-way is $10 million per year. The term of the Easement Agreement runs through December 31, 2050 and is subject to 10 automatic 50-year renewals thereafter unless METC gives notice of nonrenewal of at least one year in advance. Payments to Consumers Energy under the Easement Agreement are charged to operation and maintenance expense.
The contractual obligations table above excludes certain items, including the estimated potential refund related to the Second Complaint, contingent liabilities and other long-term liabilities, due to uncertainty on the final outcome in addition to the timing and amount of future cash flows necessary to settle these obligations. The amount of cash flows to be paid for pension and other postretirement obligations and settle regulatory liabilities related to asset removal costs and liabilities to refund deposits from generators for transmission network upgrades, which are recorded in other current and long term liabilities, are not known with certainty. As a result, cash obligations for these items are excluded from the contractual obligations table above.
Critical Accounting Policies and Estimates
Our consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The preparation of these consolidated financial statements requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. The application of these policies requires judgments regarding future events.
These estimates and judgments, in and of themselves, could materially impact the consolidated financial statements and disclosures based on varying assumptions, as future events rarely develop exactly as forecasted, and even the best estimates routinely require adjustment.
The following is a list of accounting policies that are most significant to the portrayal of our financial condition and results of operations and/or that require management’s most difficult, subjective or complex judgments.
Regulation
Our Regulated Operating Subsidiaries are subject to regulation by the FERC. As a result, we apply accounting principles in accordance with the standards set forth by the Financial Accounting Standards Board (“FASB”) for accounting for the effects of certain types of regulation. Use of this accounting guidance results in differences in the application of GAAP between regulated and non-regulated businesses and requires the recording of regulatory assets and liabilities for certain transactions that would have been treated as expense or revenue in non-regulated businesses. As described in Note 6 to the consolidated financial statements, we had regulatory assets and liabilities of $300 million and $378 million, respectively, as of December 31, 2016. Future changes in the regulatory and competitive environments could result in discontinuing the application of the accounting standards for the effects of certain types of regulations. If we were to discontinue the application of this guidance on the operations of our Regulated Operating Subsidiaries, we may be required to record losses relating to certain regulatory assets or gains relating to certain regulatory liabilities. We also may be required to record losses of $43 million relating to intangible assets at December 31, 2016 that are described in Note 7 to the consolidated financial statements.
We believe that currently available facts support the continued applicability of the standards for accounting for the effects of certain types of regulation and that all regulatory assets and liabilities are recoverable or refundable under our current rate environment.
Revenue Recognition under Cost-Based Formula Rates with True-Up Mechanism
Our Regulated Operating Subsidiaries recover expenses and earn a return on and recover investments in property, plant and equipment on a current, rather than lagging, basis, under their forward-looking cost-based formula rates with a true-up mechanism.
Under their formula rates, our Regulated Operating Subsidiaries use forecasted expenses, property, plant and equipment, point-to-point revenues and other items for the upcoming calendar year to establish their projected revenue requirement and for the MISO Regulated Operating Subsidiaries, their component of the billed network


43

rates for service on their systems from January 1 to December 31 of that year. The cost-based formula rates include a true-up mechanism, whereby our Regulated Operating Subsidiaries compare their actual revenue requirements to their billed revenues for each year in order to subsequently collect or refund any under-recovery or over-recovery of revenues, as appropriate. The under- or over-collection typically results from differences between the projected revenue requirement used as the basis for billing and actual revenue requirement at each of our Regulated Operating Subsidiaries, and from differences between actual and projected monthly peak loads at our MISO Regulated Operating Subsidiaries.
The true-up mechanism under our formula rates meet the GAAP requirements for accounting for rate-regulated utilities and the effects of certain alternative revenue programs. Accordingly, revenue is recognized during each reporting period based on actual revenue requirements calculated using the cost-based formula rates. Our Regulated Operating Subsidiaries accrue or defer revenues to the extent that their actual revenue requirement for the reporting period is higher or lower, respectively, than the amounts billed relating to that reporting period. The true-up amount is automatically reflected in customer bills within two years under the provisions of the formula rates. See Note 5 to the consolidated financial statements for the regulatory assets and liabilities recorded at our Regulated Operating Subsidiaries’ as a result of the formula rate revenue accruals and deferrals.
Valuation of Goodwill
We have goodwill resulting from our acquisitions of ITCTransmission and METC and ITC Midwest’s acquisition of the IP&L transmission assets. We perform an impairment test annually at the reporting unit level or whenever events or circumstances indicate that the value of goodwill may be impaired. In order to perform these impairment tests, we compare the fair value of each reporting unit with their respective carrying value. Our reporting units are ITCTransmission, METC and ITC Midwest as each entity represents an individual operating segment to which goodwill has been assigned. We determine fair value using valuation techniques based on discounted future cash flows under various scenarios. We also consider estimates of market-based valuation multiples for companies within the peer group of our reporting units. The market-based multiples involve judgment regarding the appropriate peer group and the appropriate multiple to apply in the valuation and the cash flow estimates involve judgments based on a broad range of assumptions, information and historical results. To the extent estimated market-based valuation multiples and/or discounted cash flows are revised downward, we may be required to write down all or a portion of goodwill, which would adversely impact earnings.
As of December 31, 2016 and 2015, consolidated goodwill totaled $950 million. We completed our annual goodwill impairment test for our reporting units as of October 1, 2016 using a qualitative assessment and determined that no impairment exists. There were no events subsequent to October 1, 2016, including the Merger consummated on October 14, 2016, that indicated impairment of our goodwill. We do not believe there is a material risk of our goodwill being impaired in the near term for any of our reporting units.
Contingent Obligations
We are subject to a number of federal and state laws and regulations, as well as other factors and conditions that potentially subject us to environmental, litigation, income tax and other contingencies. Additionally, we have other contingent obligations that may be required to be paid to developers based on achieving certain milestones relating to development initiatives. We periodically evaluate our exposure to such contingencies and record liabilities for those matters where a loss is considered probable and reasonably estimable in accordance with GAAP. Our liabilities exclude any estimates for legal costs not yet incurred associated with handling these matters, which could be material. The adequacy of liabilities recorded can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect our consolidated financial statements. These events or conditions include, without limitation, the following:
•
Changes in existing state or federal regulation by governmental authorities having jurisdiction over air quality, water quality, control of toxic substances, hazardous and solid wastes and other environmental matters.
•
Changes in existing federal income tax laws or Internal Revenue Service (“IRS”) regulations.
•
Identification and evaluation of lawsuits or complaints in which we may be or have been named as a defendant.
•
Resolution or progression of existing matters through the legislative process, the courts, the FERC, the NERC, the IRS or the Environmental Protection Agency.
•
Completion of certain milestones relating to development initiatives.


44

Refer to Note 15 to the consolidated financial statements for discussion on contingencies, including the ROE complaints.
Pension and Postretirement Costs
We sponsor certain retirement benefits for our employees, which include retirement pension plans and certain postretirement health care, dental and life insurance benefits. Our periodic costs and obligations associated with these plans are developed from actuarial valuations derived from a number of assumptions, including rates of return on plan assets, the discount rates, the rate of increase in health care costs, the amount and timing of plan sponsor contributions and demographic factors such as retirements, mortality and turnover, among others. We evaluate these assumptions annually and update them periodically to reflect our actual experience. Three critical assumptions in determining our periodic costs and obligations are discount rate, expected long-term return on plan assets and the rate of increases in health care costs. The discount rate represents the market rate for synthesized AA-rated zero-coupon bonds with durations corresponding to the expected durations of the benefit obligations and is used to calculate the present value of the expected future cash flows for benefit obligations under our plans. In determining our long-term rate of return on plan assets, we consider the current and expected asset allocations, as well as historical and expected long-term rates of return on those types of asset classes. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans as described in Note 11 to the consolidated financial statements.
Off-Balance Sheet Arrangements
We have no off-balance sheet arrangements that have or are reasonably likely to have a material effect on our financial condition.
Recent Accounting Pronouncements
See Note 3 to the consolidated financial statements.
ITEM 7A.     QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Commodity Price Risk
We have commodity price risk at our Regulated Operating Subsidiaries arising from market price fluctuations for materials such as copper, aluminum, steel, oil and gas and other goods used in construction and maintenance activities. Higher costs of these materials are passed on to us by the contractors for these activities. These items affect only cash flows, as the amounts are included as components of net revenue requirement and any higher costs are included in rates under their cost-based formula rates.
Interest Rate Risk
Fixed Rate Debt
Based on the borrowing rates currently available for bank loans with similar terms and average maturities, the fair value of our consolidated long-term debt and debt maturing within one year, excluding revolving credit agreements and commercial paper, was $4,306 million at December 31, 2016. The total book value of our consolidated long-term debt and debt maturing within one year, net of discount and deferred financing fees and excluding revolving credit agreements and commercial paper, was $4,112 million at December 31, 2016. We performed an analysis calculating the impact of changes in interest rates on the fair value of long-term debt and debt maturing within one year, excluding revolving credit agreements and commercial paper, at December 31, 2016. An increase in interest rates of 10% (from 5.0% to 5.5%, for example) at December 31, 2016 would decrease the fair value of debt by $177 million, and a decrease in interest rates of 10% at December 31, 2016 would increase the fair value of debt by $192 million at that date.
Revolving Credit Agreements
At December 31, 2016, we had a consolidated total of $334 million outstanding under our revolving agreements, which are variable rate loans and fair value approximates book value. A 10% increase or decrease in borrowing rates under the revolving credit agreements compared to the weighted average rates in effect at December 31, 2016 would increase or decrease interest expense by $1 million, respectively, for an annual period with a constant borrowing level of $334 million.


45

Commercial Paper
At December 31, 2016, ITC Holdings had $145 million of commercial paper issued and outstanding, net of discount, under the commercial paper program. Due to the short-term nature of these financial instruments, the carrying value approximates fair value. A 10% increase or decrease in interest rates for commercial paper would increase or decrease interest expense by less than $1 million for an annual period with a continuous level of commercial paper outstanding of $145 million.
Derivative Instruments and Hedging Activities
We use derivative financial instruments, including interest rate swap contracts, to manage our exposure to fluctuations in interest rates. The use of these financial instruments mitigates exposure to these risks and the variability of our operating results. We are not a party to leveraged derivatives and do not enter into derivative financial instruments for trading or speculative purposes. In June 2016, we terminated $300 million of 10-year interest rate swap contracts that managed the interest rate risk associated with the unsecured Notes issued by ITC Holdings described in Note 9 to the consolidated financial statements.
As of December 31, 2016, we held 10-year interest rate swap contracts with a notional amount of $100 million, which manage interest rate risk associated with the forecasted future issuance of fixed-rate debt related to the expected refinancing of the maturing ITC Holdings 6.05% Senior Notes, due January 31, 2018. As of December 31, 2016, ITC Holdings had $385 million outstanding under the 6.05% Senior Notes. See Note 9 to the consolidated financial statements for further discussion on these interest rate swaps.
Credit Risk
Our credit risk is primarily with DTE Electric, Consumers Energy and IP&L, which were responsible for 20.7%, 21.7% and 25.5%, respectively, or $254 million, $267 million and $314 million, respectively, of our consolidated billed revenues for 2016. These percentages of total billed revenues of DTE Electric, Consumers Energy and IP&L include the collection of 2014 revenue accruals and deferrals and exclude any amounts for the 2016 revenue accruals and deferrals that were included in our 2016 operating revenues, but will not be billed to our customers until 2018. Refer to “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cost-Based Formula Rates with True-Up Mechanism” for a discussion on the difference between billed revenues and operating revenues. Under DTE Electric’s and Consumers Energy’s current rate structure, DTE Electric and Consumers Energy include in their retail rates the actual cost of transmission services provided by ITCTransmission and METC, respectively, in their billings to their customers, effectively passing through to end-use consumers the total cost of transmission service. IP&L currently includes in their retail rates an allowance for transmission services provided by ITC Midwest in their billings to their customers. However, any financial difficulties experienced by DTE Electric, Consumers Energy or IP&L may affect their ability to make payments for transmission service to ITCTransmission, METC and ITC Midwest, which could negatively impact our business. MISO, as our MISO Regulated Operating Subsidiaries’ billing agent, bills DTE Electric, Consumers Energy, IP&L and other customers on a monthly basis and collects fees for the use of the MISO Regulated Operating Subsidiaries’ transmission systems. SPP is the billing agent for ITC Great Plains and bills transmission customers for the use of ITC Great Plains transmission systems. MISO and SPP have implemented strict credit policies for its members’ customers, which include customers using our transmission systems. Specifically, MISO and SPP require a letter of credit or cash deposit equal to the credit exposure, which is determined by a credit scoring model and other factors, from any customer using a member’s transmission system.


46

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
 
Report of Independent Registered Public Accounting Firm
 
Report of Independent Registered Public Accounting Firm
 
Consolidated Statements of Financial Position as of December 31, 2016 and 2015
 
Consolidated Statements of Operations for the Years Ended December 31, 2016, 2015 and 2014
 
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2016, 2015 and 2014
 
Consolidated Statements of Changes in Stockholders’ Equity for the Years Ended December 31, 2016, 2015 and 2014
 
Consolidated Statements of Cash Flows for the Years Ended December 31, 2016, 2015 and 2014
 
Notes to Consolidated Financial Statements
 
Schedule I — Condensed Financial Information of Registrant
 



47

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is designed to provide reasonable, not absolute, assurance as to the reliability of our financial reporting and the preparation of financial statements in accordance with generally accepted accounting principles. Internal control over financial reporting, no matter how well designed, has inherent limitations. Therefore, internal control over financial reporting determined to be effective can provide only reasonable assurance with respect to financial statement preparation and may not prevent or detect all misstatements.
Under management’s supervision, an evaluation of the design and effectiveness of our internal control over financial reporting was conducted based on the criteria set forth in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Our assessment included extensive documenting, evaluating and testing of the design and operating effectiveness of our internal control over financial reporting. Based on this evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2016.
Deloitte & Touche LLP, an independent registered public accounting firm, as auditors of our consolidated financial statements, has issued an attestation report on the effectiveness of our internal control over financial reporting as of December 31, 2016. Deloitte & Touche LLP’s report, which expresses an unqualified opinion on the effectiveness of our internal control over financial reporting, is included herein.


48

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholder of
ITC Holdings Corp.:
Novi, Michigan
We have audited the accompanying consolidated statements of financial position of ITC Holdings Corp. and subsidiaries (the “Company”) as of December 31, 2016 and 2015, and the related consolidated statements of operations, comprehensive income, changes in stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2016. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of ITC Holdings Corp. and subsidiaries as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
As discussed in Note 3 to the financial statements, the Company has changed its method of accounting for share-based payment accounting in 2016 due to the adoption of Accounting Standards Update 2016-09 Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2016, based on criteria established in the Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 16, 2017 expressed an unqualified opinion on the Company’s internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP

Detroit, Michigan
February 16, 2017


49

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholder of
ITC Holdings Corp.:
Novi, Michigan
We have audited the internal control over financial reporting of ITC Holdings Corp. and subsidiaries (the “Company”) as of December 31, 2016, based on criteria established in the Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on the criteria established in the Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2016 of the Company and our report dated February 16, 2017 expressed an unqualified opinion on those financial statements and financial statement schedule and included an explanatory paragraph regarding the Company's adoption of Accounting Standards Update 2016-09 Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting.
/s/ DELOITTE & TOUCHE LLP

Detroit, Michigan
February 16, 2017


50

ITC HOLDINGS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
 
December 31,
(In millions, except share data)
2016
 
2015
ASSETS
Current assets
 
 
 
Cash and cash equivalents
$
8

 
$
14

Accounts receivable
108

 
104

Inventory
29

 
26

Regulatory assets
53

 
15

Income tax receivable
17

 
—

Prepaid and other current assets
18

 
10

Total current assets
233

 
169

Property, plant and equipment (net of accumulated depreciation and amortization of $1,575 and $1,488, respectively)
6,698

 
6,110

Other assets
 
 
 
Goodwill
950

 
950

Intangible assets (net of accumulated amortization of $32 and $28, respectively)
43

 
46

Regulatory assets
247

 
233

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

 
2

Other
50

 
45

Total other assets
1,292

 
1,276

TOTAL ASSETS
$
8,223

 
$
7,555

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
 
 
 
Accounts payable
$
100

 
$
124

Accrued compensation
14

 
24

Accrued interest
54

 
53

Accrued taxes
49

 
44

Regulatory liabilities
129

 
45

Refundable deposits from generators for transmission network upgrades
17

 
3

Debt maturing within one year
235

 
395

Other
35

 
31

Total current liabilities
633

 
719

Accrued pension and postretirement liabilities
68

 
62

Deferred income taxes
964

 
735

Regulatory liabilities
249

 
255

Refundable deposits from generators for transmission network upgrades
27

 
18

Other
26

 
23

Long-term debt
4,355

 
4,034

Commitments and contingent liabilities (Notes 5 and 15)


 


STOCKHOLDERS’ EQUITY
 
 
 
Common stock, without par value, 235,000,000 shares authorized as of December 31, 2016, and 224,203,112 and 152,699,077 shares issued and outstanding at December 31, 2016 and 2015, respectively
892

 
829

Retained earnings
1,007

 
876

Accumulated other comprehensive income
2

 
4

Total stockholders’ equity
1,901

 
1,709

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
$
8,223

 
$
7,555

See notes to consolidated financial statements.


51

ITC HOLDINGS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
 
Year Ended December 31,
(In millions)
2016
 
2015
 
2014
OPERATING REVENUES
$
1,125

 
$
1,045

 
$
1,023

OPERATING EXPENSES
 
 
 
 
 
Operation and maintenance
114

 
113

 
112

General and administrative
239

 
145

 
115

Depreciation and amortization
158

 
145

 
128

Taxes other than income taxes
93

 
82

 
76

Other operating income and expense — net
(1
)
 
(1
)
 
(1
)
Total operating expenses
603

 
484

 
430

OPERATING INCOME
522

 
561

 
593

OTHER EXPENSES (INCOME)
 
 
 
 
 
Interest expense — net
211

 
204

 
187

Allowance for equity funds used during construction
(35
)
 
(28
)
 
(21
)
Loss on extinguishment of debt
—

 
—

 
29

Other income
(2
)
 
(2
)
 
(1
)
Other expense
5

 
3

 
5

Total other expenses (income)
179

 
177

 
199

INCOME BEFORE INCOME TAXES
343

 
384

 
394

INCOME TAX PROVISION
97

 
142

 
150

NET INCOME
$
246

 
$
242

 
$
244

See notes to consolidated financial statements.


52

ITC HOLDINGS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 
Year Ended December 31,
(In millions)
2016
 
2015
 
2014
NET INCOME
$
246

 
$
242

 
$
244

OTHER COMPREHENSIVE LOSS
 
 
 
 
 
Derivative instruments, net of tax (Note 13)
(2
)
 
(1
)
 
(2
)
TOTAL OTHER COMPREHENSIVE LOSS, NET OF TAX (NOTE 13)
(2
)
 
(1
)
 
(2
)
TOTAL COMPREHENSIVE INCOME
$
244

 
$
241

 
$
242

See notes to consolidated financial statements.


53

ITC HOLDINGS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN
STOCKHOLDERS’ EQUITY
 
 
 
 
 
Accumulated
 
 
 
 
 
 
 
Other
 
Total
 
 
 
Retained
 
Comprehensive
 
Stockholders’
 
Common Stock
 
Earnings
 
Income (Loss)
 
Equity
(In millions)
 
 
 
 
 
 
 
BALANCE, DECEMBER 31, 2013
$
1,014

 
$
593

 
$
7

 
$
1,614

Net income
—

 
244

 
—

 
244

Repurchase and retirement of common stock
(134
)
 
—

 
—

 
(134
)
Dividends declared on common stock
—

 
(96
)
 
—

 
(96
)
Stock option exercises
19

 
—

 
—

 
19

Share-based compensation, net of forfeitures
15

 
—

 
—

 
15

Tax benefit for excess tax deductions of share-based compensation
8

 
—

 
—

 
8

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

 
—

 
(2
)
 
(2
)
Other
2

 
—

 
—

 
2

BALANCE, DECEMBER 31, 2014
$
924

 
$
741

 
$
5

 
$
1,670

Net income
—

 
242

 
—

 
242

Repurchase and retirement of common stock
(137
)
 
—

 
—

 
(137
)
Dividends declared on common stock
—

 
(108
)
 
—

 
(108
)
Stock option exercises
11

 
—

 
—

 
11

Share-based compensation, net of forfeitures
18

 
—

 
—

 
18

Tax benefit for excess tax deductions of share-based compensation
12

 
—

 
—

 
12

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

 
—

 
(1
)
 
(1
)
Other
1

 
1

 
—

 
2

BALANCE, DECEMBER 31, 2015
$
829

 
$
876

 
$
4

 
$
1,709

Net income
—

 
246

 
—

 
246

Repurchase and retirement of common stock
(9
)
 
—

 
—

 
(9
)
Dividends declared on common stock
—

 
(90
)
 
—

 
(90
)
Dividends to ITC Investment Holdings Inc.
—

 
(33
)
 
—

 
(33
)
Stock option exercises
11

 
—

 
—

 
11

Share-based compensation, net of forfeitures
18

 
—

 
—

 
18

Share-based compensation associated with the Merger (Note 13)
41

 
—

 
—

 
41

Settlement of share-based awards associated with the Merger (Note 13)
(137
)
 
(1
)
 
—

 
(138
)
Contribution from ITC Investment Holdings Inc. for the settlement of shared-based awards associated with the Merger (Note 13)
137

 
—

 
—

 
137

Tax benefit for excess tax deductions of share-based compensation (Note 3)
—

 
9

 
—

 
9

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

 
—

 
(2
)
 
(2
)
Other
2

 
—

 
—

 
2

BALANCE, DECEMBER 31, 2016
$
892

 
$
1,007

 
$
2

 
$
1,901

See notes to consolidated financial statements.


54

ITC HOLDINGS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
Year Ended December 31,
(In millions)
2016
 
2015
 
2014
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
 
 
Net income
$
246

 
$
242

 
$
244

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
 
Depreciation and amortization expense
158

 
145

 
128

Recognition, refund and collection of revenue accruals and deferrals — including accrued interest
(2
)
 
(54
)
 
(4
)
Deferred income tax expense
219

 
77

 
90

Allowance for equity funds used during construction
(35
)
 
(28
)
 
(21
)
Expense for the accelerated vesting of share-based awards associated with the Merger
41

 
—

 
—

Loss on extinguishment of debt
—

 
—

 
29

Other
30

 
22

 
18

Changes in assets and liabilities, exclusive of changes shown separately:
 
 
 
 
 
Accounts receivable
(2
)
 
(1
)
 
(12
)
Current regulatory assets
(29
)
 
—

 
—

Income tax receivable
(17
)
 
—

 
—

Other current assets
(4
)
 
2

 
6

Accounts payable
5

 
(7
)
 
(19
)
Accrued compensation
(11
)
 
—

 
1

Accrued taxes
4

 
15

 
20

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

 
(12
)
 
(8
)
Other current liabilities
3

 
9

 
(5
)
Estimated refund related to return on equity complaints
90

 
120

 
48

Other non-current assets and liabilities, net
(9
)
 
26

 
(13
)
Net cash provided by operating activities
687

 
556

 
502

CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
 
 
Expenditures for property, plant and equipment
(750
)
 
(701
)
 
(753
)
Contributions in aid of construction
11

 
17

 
20

Other
4

 
(16
)
 
(2
)
Net cash used in investing activities
(735
)
 
(700
)
 
(735
)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
 
 
Issuance of long-term debt, net of discount
599

 
225

 
799

Borrowings under revolving credit agreements
1,042

 
2,832

 
1,660

Borrowings under term loan credit agreements
—

 
200

 
110

Net issuance of commercial paper, net of discount
48

 
95

 
—

Retirement of long-term debt — including extinguishment of debt costs
(139
)
 
(175
)
 
(299
)
Repayments of revolving credit agreements
(1,028
)
 
(2,825
)
 
(1,618
)
Repayments of term loan credit agreements
(361
)
 
—

 
(189
)
Issuance of common stock
13

 
14

 
21

Dividends on common and restricted stock
(90
)
 
(108
)
 
(96
)
Dividends to ITC Investment Holdings Inc.
(33
)
 
—

 
—

Refundable deposits from generators for transmission network upgrades
33

 
13

 
6

Repayment of refundable deposits from generators for transmission network upgrades
(10
)
 
(12
)
 
(29
)
Repurchase and retirement of common stock
(9
)
 
(137
)
 
(134
)
Settlement of share-based awards associated with the Merger — including cost of accelerated share-based awards
(137
)
 
—

 
—

Contribution from ITC Investment Holdings Inc. for the settlement of share-based awards associated with the Merger
137

 
—

 
—

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

 
12

 
8

Advance for forward contract of accelerated share repurchase program
—

 
—

 
(20
)
Return of unused advance for forward contract of accelerated share repurchase program
—

 
—

 
20

Other
(23
)
 
(4
)
 
(12
)
Net cash provided by financing activities
42

 
130

 
227

NET DECREASE IN CASH AND CASH EQUIVALENTS
(6
)
 
(14
)
 
(6
)
CASH AND CASH EQUIVALENTS — Beginning of period
14

 
28

 
34

CASH AND CASH EQUIVALENTS — End of period
$
8

 
$
14

 
$
28

See notes to consolidated financial statements.


55

ITC HOLDINGS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1.    GENERAL
ITC Holdings Corp. (“ITC Holdings,” and together with its subsidiaries, “we,” “our” or “us”) and its subsidiaries are engaged in the transmission of electricity in the United States. Through our operating subsidiaries, ITCTransmission, METC, ITC Midwest, ITC Great Plains and ITC Interconnection (together, our “Regulated Operating Subsidiaries”), we operate high-voltage systems in Michigan and portions of Iowa, Minnesota, Illinois, Missouri, Kansas and Oklahoma that transmit electricity from generating stations to local distribution facilities connected to our systems. Our business strategy is to operate, maintain and invest in transmission infrastructure in order to enhance system integrity and reliability, reduce transmission constraints and allow new generating resources to interconnect to our transmission systems. We also are pursuing transmission development projects not within our existing systems, which are intended to improve overall grid reliability, lower electricity congestion and facilitate interconnections of new generating resources, as well as enhance competitive wholesale electricity markets.
Our Regulated Operating Subsidiaries are independent electric transmission utilities, with rates regulated by the FERC and established on a cost-of-service model. ITCTransmission’s service area is located in southeastern Michigan, while METC’s service area covers approximately two-thirds of Michigan’s Lower Peninsula and is contiguous with ITCTransmission’s service area. ITC Midwest’s service area is located in portions of Iowa, Minnesota, Illinois and Missouri and ITC Great Plains currently owns assets located in Kansas and Oklahoma. The Midcontinent Independent System Operator, Inc. (“MISO”) bills and collects revenues from ITCTransmission, METC and ITC Midwest (“MISO Regulated Operating Subsidiaries”) customers. The Southwest Power Pool, Inc. (“SPP”) bills and collects revenue from ITC Great Plains customers. ITC Interconnection currently owns assets in Michigan and earns revenues based on its facilities reimbursement agreement with a merchant generating company.
2.    THE MERGER
On February 9, 2016, Fortis Inc. (“Fortis”), FortisUS Inc. (“FortisUS”), Element Acquisition Sub Inc. (“Merger Sub”) and ITC Holdings entered into an agreement and plan of merger (the “Merger Agreement”), pursuant to which Merger Sub would merge with and into ITC Holdings with ITC Holdings continuing as a surviving corporation and becoming a majority owned indirect subsidiary of Fortis (the “Merger”). On April 20, 2016, FortisUS assigned its rights, interest, duties and obligations under the Merger Agreement to ITC Investment Holdings Inc. (“Investment Holdings”), a subsidiary of FortisUS formed to complete the Merger. On the same date, Fortis reached a definitive agreement with a subsidiary of GIC Private Limited (“GIC”) for GIC to acquire an indirect 19.9% equity interest in ITC Holdings and debt securities to be issued by Investment Holdings for aggregate consideration of $1.228 billion in cash upon completion of the Merger. On October 14, 2016, ITC Holdings and Fortis completed the Merger contemplated by the Merger Agreement consistent with the terms described above. On the same date, the common shares of ITC Holdings were delisted from the New York Stock Exchange (“NYSE”) and the common shares of Fortis were listed and began trading on the NYSE. Fortis continues to have its shares listed on the Toronto Stock Exchange.
In the Merger, ITC Holdings shareholders received $22.57 in cash and 0.7520 Fortis common shares for each share of common stock of ITC Holdings (the “Merger consideration”). Upon completion of the Merger, ITC Holdings shareholders held approximately 27% of the common shares of Fortis. Under the Merger Agreement, outstanding share-based awards vested as described in Note 13. The per share amount of Merger consideration determined in accordance with the Merger Agreement and used for purposes of settling the share-based awards was $45.72. We elected not to apply pushdown accounting to ITC Holdings or its subsidiaries in connection with the Merger.
For the year ended December 31, 2016, we expensed external legal, advisory and financial services fees related to the Merger of $55 million and certain internal labor and associated costs related to the Merger of approximately $58 million, including approximately $41 million of expense recognized due to the accelerated vesting of the share-based awards described in Note 13. These merger-related costs were recorded within general and administrative expenses. The external and internal costs related to the Merger were recorded at ITC Holdings and have not been included as components of revenue requirement at our Regulated Operating Subsidiaries.
See Note 15 for legal matters associated with the Merger with Fortis.


56

3.    RECENT ACCOUNTING PRONOUNCEMENTS
Recently Adopted Pronouncements
Amendment to the Balance Sheet Presentation of Debt Issuance Costs
In April 2015, the Financial Accounting Standards Board (“FASB”) issued authoritative guidance that amends the balance sheet presentation of debt issuance costs. This new standard requires debt issuance costs to be shown as a direct deduction from the carrying amount of the related debt, consistent with debt discounts. The guidance is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2015. On January 1, 2016, we adopted this guidance retrospectively and have applied this change to all amounts presented in our consolidated statements of financial position. The following shows the impact of this adoption on our previously reported consolidated statement of financial position as of December 31, 2015:
(in millions)
Reported
 
Adjustment
 
Adjusted
Deferred financing fees (net of accumulated amortization)
$
29

 
$
(27
)
 
$
2

Debt maturing within one year
395

 
—

 
395

Long-term debt
4,061

 
(27
)
 
4,034

We have accounted for this adoption as a change in accounting principle that is required due to a change in the authoritative accounting guidance. In connection with implementing this guidance, we adopted an accounting policy to present unamortized debt issuance costs associated with revolving credit agreements, commercial paper and other similar arrangements as an asset that is amortized over the life of the particular arrangement. In addition, we present debt issuance costs incurred prior to the associated debt funding as an asset for all other debt arrangements. This standard did not impact our consolidated statements of operations or cash flows.
Simplification of Employee Share-Based Payment Accounting
In March 2016, the FASB issued authoritative guidance that simplifies several aspects of the accounting for employee share-based payment transactions. The new guidance (1) requires that an entity recognize all excess tax benefits and tax deficiencies as income tax benefit or expense in the income statement, (2) allows an entity to elect as an accounting policy to either estimate forfeitures or account for forfeitures when they occur, (3) modifies the current exception to liability classification of an award when an employer uses a net-settlement feature to withhold shares to meet the employer’s minimum statutory tax withholding requirement to apply if the withholding amount does not exceed the maximum statutory tax rate and (4) specifies the statement of cash flow presentation for excess tax benefits and cash payments to taxing authorities when shares are withheld to meet tax withholding requirements.
We elected to early adopt the guidance during the fourth quarter of 2016. Upon adoption, we elected an accounting policy of recognizing forfeitures as they occur. The impact of this change was not material. In addition, we recorded a deferred tax asset through an adjustment to retained earnings of $9 million for state income tax net operating losses, related to excess tax benefits generated in periods prior to 2016 that had not been previously recognized in the consolidated statements of financial position. These aspects were adopted on a modified retrospective basis as of January 1, 2016. We also recorded an increase in deferred tax assets and a credit to income tax expense in 2016 for a total of $27 million for excess tax benefits generated during the year ended December 31, 2016; this change was adopted on a prospective basis as of January 1, 2016.
As a result of adoption, we began presenting excess tax benefits and deficiencies within operating activities on the statement of cash flows and adopted this change prospectively as of January 1, 2016; previously, such amounts were presented within financing activities. Therefore, the statements of cash flows for prior periods have not been adjusted. There were no other material impacts to our consolidated financial statements as a result of the other aspects of the guidance.
Recently Issued Pronouncements
We have considered all new accounting pronouncements issued by the FASB and concluded the following accounting guidance, which has not yet been adopted by us, may have a material impact on our consolidated financial statements.


57

Revenue Recognition
In May 2014, the FASB issued authoritative guidance requiring entities to apply a new model for recognizing revenue from contracts with customers. The guidance will supersede the current revenue recognition guidance and requires entities to evaluate their revenue recognition arrangements using a five-step model to determine when a customer obtains control of a transferred good or service. The majority of our revenue is generated from sales based on tariff rates, as approved by FERC, and is considered to be in the scope of the new guidance. However, we do not expect that the adoption of this guidance will have a material impact on our consolidated results of operations, cash flows or financial position. We continue to closely monitor outstanding industry specific interpretative issues, including contributions in aid of construction.
The guidance is effective for annual reporting periods beginning after December 15, 2017 and may be adopted using either (a) a full retrospective method, whereby comparative periods would be restated to present the impact of the new standard, with the cumulative effective of applying the standard recognized as of the earliest period presented, or (b) a modified retrospective method, under which comparative periods would not be restated and the cumulative effective of applying the standard would be recognized at the date of initial adoption, January 1, 2018. While we expect to use the modified retrospective approach, we continue to monitor industry developments and the outcome of those matters may impact our ultimate decision regarding transition method. 
Classification and Measurement of Financial Instruments
In January 2016, the FASB issued authoritative guidance amending the classification and measurement of financial instruments. The guidance requires entities to carry most investments in equity securities at fair value and recognize changes in fair value in net income, unless the investment results in consolidation or equity method accounting. Additionally, the new guidance amends certain disclosure requirements associated with the fair value of financial instruments. The guidance is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted. The guidance is required to be adopted using a modified retrospective approach, with limited exceptions. We are currently assessing the impacts this guidance will have on our consolidated financial statements, including our disclosures.
Accounting for Leases
In February 2016, the FASB issued authoritative guidance on accounting for leases, which impacts accounting by lessees as well as lessors. The new guidance creates a dual approach for lessee accounting, with lease classification determined in accordance with principles in existing lease guidance. Income statement presentation differs depending on the lease classification; however, both types of leases result in lessees recognizing a right-of-use asset and a lease liability, with limited exceptions. Under existing accounting guidance, operating leases are not recorded on the balance sheet of lessees. The new guidance is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years and will be applied using a modified retrospective approach, with possible optional practical expedients. Early adoption is permitted. We are currently assessing the impacts this guidance will have on our consolidated financial statements, including our disclosures.
4.    SIGNIFICANT ACCOUNTING POLICIES
A summary of the major accounting policies followed in the preparation of the accompanying consolidated financial statements, which conform to accounting principles generally accepted in the United States of America (“GAAP”), is presented below:
Principles of Consolidation — ITC Holdings consolidates its majority owned subsidiaries. We eliminate all intercompany balances and transactions.
Use of Estimates — The preparation of the consolidated financial statements in accordance with GAAP requires us to use estimates and assumptions that impact the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. Actual results may differ from our estimates.
Regulation — Our Regulated Operating Subsidiaries are subject to the regulatory jurisdiction of the FERC, which issues orders pertaining to rates, recovery of certain costs, including the costs of transmission assets and regulatory assets, conditions of service, accounting, financing authorization and operating-related matters. The utility operations of our Regulated Operating Subsidiaries meet the accounting standards set


58

forth by the FASB for the accounting effects of certain types of regulation. These accounting standards recognize the cost based rate setting process, which results in differences in the application of GAAP between regulated and non-regulated businesses. These standards require the recording of regulatory assets and liabilities for certain transactions that would have been recorded as revenue and expense in non-regulated businesses. Regulatory assets represent costs that will be included as a component of future tariff rates and regulatory liabilities represent amounts provided in the current tariff rates that are intended to recover costs expected to be incurred in the future or amounts to be refunded to customers.
Cash and Cash Equivalents — We consider all unrestricted highly-liquid temporary investments with an original maturity of three months or less at the date of purchase to be cash equivalents.
Consolidated Statements of Cash Flows — The following table presents certain supplementary cash flows information for the years ended December 31, 2016, 2015 and 2014:
 
Year Ended December 31,
(In millions)
2016
 
2015
 
2014
Supplementary cash flows information:
 
 
 
 
 
Interest paid (net of interest capitalized)
$
190

 
$
191

 
$
185

Income taxes paid (a)
23

 
56

 
45

Supplementary non-cash investing and financing activities:
 
 
 
 
 
Additions to property, plant and equipment and other long-lived assets (b)
$
93

 
$
110

 
$
91

Allowance for equity funds used during construction
35

 
28

 
21

____________________________
(a)
Amount for the year ended December 31, 2016 does not include the income tax refund of $128 million received from the Internal Revenue Service (“IRS”) in August 2016, which resulted from the election of bonus depreciation as described in Note 5.
(b)
Amounts consist of current liabilities for construction labor and materials that have not been included in investing activities. These amounts have not been paid for as of December 31, 2016, 2015 or 2014, respectively, but have been or will be included as a cash outflow from investing activities for expenditures for property, plant and equipment when paid.
Excess tax benefits are recognized as an adjustment to income tax expense in the statement of operations. Cash retained as a result of those excess tax benefits is presented in the statement of cash flows as cash inflows from operating activities.
Accounts Receivable — We recognize losses for uncollectible accounts based on specific identification of any such items. As of December 31, 2016 and 2015, we did not have an accounts receivable reserve.
Inventories — Materials and supplies inventories are valued at average cost. Additionally, the costs of warehousing activities are recorded here and included in the cost of materials when requisitioned.
Property, Plant and Equipment — Depreciation and amortization expense on property, plant and equipment was $149 million, $136 million and $119 million for 2016, 2015 and 2014, respectively.
Property, plant and equipment in service at our Regulated Operating Subsidiaries is stated at its original cost when first devoted to utility service. The gross book value of assets retired less salvage proceeds is charged to accumulated depreciation. The provision for depreciation of transmission assets is a significant component of our Regulated Operating Subsidiaries’ cost of service under FERC-approved rates. Depreciation is computed over the estimated useful lives of the assets using the straight-line method for financial reporting purposes and accelerated methods for income tax reporting purposes. The composite depreciation rate for our Regulated Operating Subsidiaries included in our consolidated statements of operations was 2.0%, 2.1% and 2.1% for 2016, 2015 and 2014, respectively. The composite depreciation rates include depreciation primarily on transmission station equipment, towers, poles and overhead and underground lines that have a useful life ranging from 48 to 60 years. The portion of depreciation expense related to asset removal costs is added to regulatory liabilities or deducted from regulatory assets and removal costs incurred are deducted from regulatory liabilities or added to regulatory assets. Certain of our Regulated Operating Subsidiaries capitalize to property, plant and equipment an allowance for the cost of equity and


59

borrowings used during construction (“AFUDC”) in accordance with the FERC regulations. AFUDC represents the composite cost incurred to fund the construction of assets, including interest expense and a return on equity capital devoted to construction of assets. The interest component of AFUDC of $9 million, $7 million and $5 million was a reduction to interest expense for 2016, 2015 and 2014, respectively. Certain projects at ITC Great Plains have been granted an incentive to include construction work in progress balances in rate base and we do not record AFUDC on those projects.
For acquisitions of property, plant and equipment greater than the net book value (other than asset acquisitions accounted for under the purchase method of accounting that result in goodwill), the acquisition premium is recorded to property, plant and equipment and amortized over the estimated remaining useful lives of the assets using the straight-line method for financial reporting purposes and accelerated methods for income tax reporting purposes.
Property, plant and equipment includes capital equipment inventory stated at original cost consisting of items that are expected to be used exclusively for capital projects.
Property, plant and equipment at ITC Holdings and non-regulated subsidiaries is stated at its acquired cost. Proceeds from salvage less the net book value of the disposed assets is recognized as a gain or loss on disposal. Depreciation is computed based on the acquired cost less expected residual value and is recognized over the estimated useful lives of the assets on a straight-line method for financial reporting purposes and accelerated methods for income tax reporting purposes.
Generator Interconnection Projects and Contributions in Aid of Construction — Certain capital investment at our Regulated Operating Subsidiaries relates to investments made under generator interconnection agreements. The generator interconnection agreements typically consist of both transmission network upgrades, which are a category of upgrades deemed by the FERC to benefit the transmission system as a whole, as well as direct connection facilities, which are necessary to interconnect the generating facility to the transmission system and primarily benefit the generating facility.
Our investments in transmission facilities are recorded to property, plant and equipment, and are recorded net of any contribution in aid of construction. Contributions in aid of construction of $11 million, $17 million and $20 million were recorded as reductions to property, plant and equipment during the years ended December 31, 2016, 2015 or 2014, respectively, and are included as cash inflows provided by investing activities in our consolidated statements of cash flows when received. We also receive refundable deposits from the generator for certain investment in network upgrade facilities in advance of construction, which are recorded to current or non-current liabilities depending on the expected refund date.
Available-For-Sale Securities — We have certain investments in debt and equity securities that are classified as available-for-sale securities. These investments currently fund our two supplemental nonqualified, noncontributory, retirement benefit plans for selected management employees as described in Note 11. Unrealized gains recorded for the investments are recognized, net of tax, in the accumulated other comprehensive income component of equity. Any unrealized losses (where cost exceeds fair market value) on the investments will also be recorded in the accumulated other comprehensive income component of equity, unless the unrealized loss is other than temporary, in which case it would be recorded as an investment loss in the consolidated statements of operations.
Impairment of Long-Lived Assets — Other than goodwill, our long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate the carrying amount of an asset may not be recoverable. If the carrying amount of the asset exceeds the expected undiscounted future cash flows generated by the asset, the asset is written down to its estimated fair value and an impairment loss is recognized in our consolidated statements of operations.
Goodwill — Goodwill is not subject to amortization; however, goodwill is required to be assessed for impairment, and a resulting write-down, if any, is to be reflected in operating expense. We have goodwill recorded relating to our acquisitions of ITCTransmission and METC and ITC Midwest’s acquisition of the Interstate Power and Light Company (“IP&L”) transmission assets. Goodwill is reviewed at the reporting unit level at least annually for impairment and whenever facts or circumstances indicate that the value of goodwill may be impaired. Our reporting units are ITCTransmission, METC and ITC Midwest as each entity represents an individual operating segment to which goodwill has been assigned. In order to perform an impairment analysis, we have the option of performing a qualitative assessment to determine whether it is more likely


60

than not that the fair value of a reporting unit is greater than its carrying amount, in which case no further testing is required. If an entity bypasses the qualitative assessment or performs a qualitative assessment but determines that it is more likely than not that a reporting unit’s fair value is less than its carrying amount, a quantitative two-step, fair value-based test is performed to assess and measure goodwill impairment, if any. If a quantitative assessment is performed, we determine the fair value of our reporting units using valuation techniques based on discounted future cash flows under various scenarios and consider estimates of market-based valuation multiples for companies within the peer group of our reporting units.
We completed our annual goodwill impairment test for our reporting units as of October 1, 2016 and determined that no impairment exists. There were no events subsequent to October 1, 2016, including the Merger consummated on October 14, 2016, that indicated impairment of our goodwill. Our intangible assets other than goodwill have finite lives and are amortized over their useful lives. Refer to Note 7 for additional discussion on our goodwill and intangible assets.
Deferred Financing Fees and Discount or Premium on Debt — Costs related to the issuance of long-term debt are generally recorded as a direct deduction from the carrying amount of the related debt and amortized over the life of the debt issue. Debt issuance costs incurred prior to the associated debt funding are presented as an asset. Unamortized debt issuance costs associated with the revolving credit agreements, commercial paper and other similar arrangements are presented as an asset (regardless of whether there are any amounts outstanding under those credit facilities) and amortized over the life of the particular arrangement. The debt discount or premium related to the issuance of long-term debt is recorded to long-term debt and amortized over the life of the debt issue. We recorded $4 million to interest expense for the amortization of deferred financing fees and debt discounts during each of the years ended December 31, 2016, 2015 and 2014.
Asset Retirement Obligations — A conditional asset retirement obligation is a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within our control. We have identified conditional asset retirement obligations primarily associated with the removal of equipment containing polychlorinated biphenyls (“PCBs”) and asbestos. We record a liability at fair value for a legal asset retirement obligation in the period in which it is incurred. When a new legal obligation is recorded, we capitalize the costs of the liability by increasing the carrying amount of the related long-lived asset. We accrete the liability to its present value each period and depreciate the capitalized cost over the useful life of the related asset. At the end of the asset’s useful life, we settle the obligation for its recorded amount. The standards for asset retirement obligations applied to our Regulated Operating Subsidiaries require us to recognize regulatory assets for the timing differences between the incurred costs to settle our legal asset retirement obligations and the recognition of such obligations under the standards set forth by the FASB. There were no significant changes to our asset retirement obligations in 2016. Our asset retirement obligations as of December 31, 2016 and 2015 of $5 million are included in other liabilities.
Financial Instruments — For derivative instruments that have been designated and qualify as cash flow hedges of the exposure to variability in expected future cash flows, the gain or loss on the derivative is initially reported as a component of other comprehensive income (loss) and reclassified to the consolidated statement of operations when the underlying hedged transaction affects net income. Any hedge ineffectiveness is recognized in net income immediately at the time the gain or loss on the derivative instruments is calculated. Refer to Note 9 for additional discussion regarding derivative instruments. Cash flows related to derivative instruments that are designated in hedging relationships are generally classified on the statement of cash flows in the same category as the cash flows from the associated hedged item.
Contingent Obligations — We are subject to a number of federal and state laws and regulations, as well as other factors and conditions that potentially subject us to environmental, litigation and other risks. We periodically evaluate our exposure to such risks and record liabilities for those matters when a loss is considered probable and reasonably estimable in accordance with GAAP. Our liabilities exclude any estimates for legal costs not yet incurred associated with handling these matters. The adequacy of liabilities can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect our consolidated financial statements.
Revenues — Revenues from the transmission of electricity are recognized as services are provided based on FERC-approved cost-based formula rates. We record a reserve for revenue subject to refund when such


61

refund is probable and can be reasonably estimated. This reserve is recorded as a reduction to operating revenues.
The cost-based formula rates at our Regulated Operating Subsidiaries include a true-up mechanism, whereby they compare their actual revenue requirements to their billed revenues for each year to determine any over- or under-collection of revenue requirements and record a revenue accrual or deferral for the difference. Refer to Note 5 under “Cost-Based Formula Rates with True-Up Mechanism” for a discussion of our revenue accounting under our cost-based formula rates.
Comprehensive Income (Loss) — Comprehensive income (loss) is the change in common stockholders’ equity during a period arising from transactions and events from non-owner sources, including net income, any gain or loss recognized for the effective portion of our interest rate swaps and any unrealized gain or loss associated with our available-for-sale securities.
Income Taxes — Deferred income taxes are recognized for the expected future tax consequences of events that have been recognized in the financial statements or tax returns. Deferred tax assets and liabilities are determined based on the differences between the financial statements and the tax bases of various assets and liabilities, using the tax rates expected to be in effect for the year in which the differences are expected to reverse, and classified as non-current in our consolidated statement of financial position.
The accounting standards for uncertainty in income taxes prescribe a recognition threshold and a measurement attribute for tax positions taken, or expected to be taken, in a tax return that may not be sustainable. As of December 31, 2016, we have not recognized any uncertain income tax positions.
We file income tax returns with the Internal Revenue Service and with various state and city jurisdictions. We are no longer subject to U.S. federal tax examinations for tax years 2012 and earlier. State and city jurisdictions that remain subject to examination range from tax years 2012 to 2015. In the event we are assessed interest or penalties by any income tax jurisdictions, interest and penalties would be recorded as interest expense and other expense, respectively, in our consolidated statements of operations.
5.    REGULATORY MATTERS
Rate of Return on Equity Complaints
See “Rate of Return on Equity Complaints” in Note 15 for a discussion of the complaints.
Cost-Based Formula Rates with True-Up Mechanism
The transmission revenue requirements at our Regulated Operating Subsidiaries are set annually, using FERC-approved formula rates (“formula rates”), and remain in effect for a one-year period. By updating their formula rates on an annual basis, the revenues at our Regulated Operating Subsidiaries reflect changing operational data and financial performance, including the amount of network load on their transmission systems (for our MISO Regulated Operating Subsidiaries), operating expenses and additions to property, plant and equipment when placed in service, among other items. The formula rates do not require further action or FERC filings each year, although the template inputs remain subject to legal challenge at the FERC. Our Regulated Operating Subsidiaries will continue to use formula rates to calculate their respective annual revenue requirements unless the FERC determines the rates to be unjust and unreasonable or another mechanism is determined by the FERC to be just and reasonable. See “Rate of Return on Equity Complaints” in Note 15 for detail on return on equity (“ROE”) matters.
Our formula rates include a true-up mechanism, whereby our Regulated Operating Subsidiaries compare their actual revenue requirements to their billed revenues for each year to determine any over- or under-collection of revenue requirements. Revenue is recognized for services provided during each reporting period based on actual revenue requirements calculated using the formula rates. Our Regulated Operating Subsidiaries accrue or defer revenues to the extent that the actual revenue requirement for the reporting period is higher or lower, respectively, than the amounts billed relating to that reporting period. The amount of accrued or deferred revenues is reflected in future revenue requirements and thus flows through to customer bills within two years under the provisions of the formula rates.


62

The net changes in regulatory assets and liabilities associated with our Regulated Operating Subsidiaries’ formula rate revenue accruals and deferrals, including accrued interest, were as follows during the year ended December 31, 2016:
(In millions)
 
Total
Net regulatory liability as of December 31, 2015
 
$
(3
)
Net refund of 2014 revenue deferrals and accruals, including accrued interest
 
23

Net revenue deferral for the year ended December 31, 2016
 
(20
)
Net accrued interest payable for the year ended December 31, 2016
 
(1
)
Net regulatory liability as of December 31, 2016
 
$
(1
)
Regulatory assets and liabilities associated with our Regulated Operating Subsidiaries’ formula rate revenue accruals and deferrals, including accrued interest, are recorded in the consolidated statements of financial position at December 31, 2016 as follows:
(In millions)
 
Total
Current regulatory assets
 
$
24

Non-current regulatory assets
 
16

Current regulatory liabilities
 
(9
)
Non-current regulatory liabilities
 
(32
)
Net regulatory liability as of December 31, 2016
 
$
(1
)
ITCTransmission Regional Cost Allocation Refund
In October 2010, MISO and ITCTransmission made a filing with the FERC under Section 205 of the FPA to revise the MISO tariff to establish a methodology to allocate and recover costs of ITCTransmission’s Phase Angle Regulating Transformers (“PARs”) among MISO and other FERC-approved Regional Transmission Organizations (“RTOs”) — the New York Independent System Operator and PJM Interconnection (“other RTOs”). In December 2010, the FERC accepted the proposed revisions, subject to refund, while setting them for hearing and settlement procedures. On September 22, 2016, the FERC issued an order largely affirming the presiding administrative law judge’s initial decision issued in December 2012, which stated, among other things, that MISO and ITCTransmission failed to show that the other RTOs will benefit from the operation of ITCTransmission’s PARs. The FERC order required ITCTransmission to provide refunds within 30 days for excess amounts collected from customers of the other RTOs. The refunds, including interest, were provided to the other RTOs in October 2016. As a result of the FERC order, ITCTransmission will collect the amounts refunded, plus interest, from network customers. On December 6, 2016, ITCTransmission made a filing with the FERC, under Section 205 of the FPA, requesting to recover the amount refunded to the other RTOs (“regional cost allocation recovery”) in network rates during the next calendar year, beginning January 1, 2017. On January 30, 2017, the FERC issued an order approving collection of the regional cost allocation recovery in 2017. ITCTransmission has recorded $29 million for the regional cost allocation recovery, including interest, in current regulatory assets on the consolidated statement of financial position as of December 31, 2016.
ITC Interconnection
ITC Interconnection was formed in 2014 by ITC Holdings to pursue transmission investment opportunities. On June 1, 2016, ITC Interconnection acquired certain transmission assets from a merchant generating company and placed a newly constructed 345 kV transmission line in service. As a result, ITC Interconnection became a transmission owner in PJM Interconnection, and is subject to rate regulation by the FERC. The revenues earned by ITC Interconnection are based on its facilities reimbursement agreement with the merchant generating company. The financial results of ITC Interconnection are currently not material to our consolidated financial statements.
MISO Funding Policy for Generator Interconnections
On June 18, 2015, the FERC issued an order initiating a proceeding, pursuant to Section 206 of the FPA, to examine MISO’s funding policy for generator interconnections, which allows a transmission owner to unilaterally elect to fund network upgrades and recover such costs from the interconnection customer. In this order, the FERC


63

suggested the MISO funding policy be revised to require mutual agreement between the interconnection customer and transmission owner to utilize the election to fund network upgrades. On January 8, 2016, MISO made a compliance filing to revise its funding policy to adopt the FERC suggestion to require mutual agreement between the customer and TO, with an effective date of June 24, 2015. ITCTransmission, METC and ITC Midwest, along with another MISO TO, are currently appealing the FERC’s orders on this issue. We do not expect the resolution of this proceeding to have a material impact on our consolidated results of operations, cash flows or financial condition.
MISO Formula Rate Template Modifications Filing
On October 30, 2015, our MISO Regulated Operating Subsidiaries requested modifications, pursuant to Section 205 of the FPA, to certain aspects of their respective FERC-approved formula rate templates which included, among other things, changes to ensure that various income tax items are computed correctly for purposes of determining their revenue requirements. Our MISO Regulated Operating Subsidiaries requested an effective date of January 1, 2016 for the proposed template changes. On December 30, 2015, the FERC conditionally accepted the formula rate template modifications and required a further compliance filing, which was made on February 8, 2016. On April 14, 2016, the FERC issued an order accepting the February 8, 2016 compliance filing, effective January 1, 2016. The formula rate templates, prior to any proposed modifications, include certain deferred income taxes on contributions in aid of construction in rate base that resulted in recovery of excess amounts from customers. As of December 31, 2016 and 2015, our MISO Regulated Operating Subsidiaries had recorded an aggregate refund liability of $2 million and $10 million, respectively.
Challenges Regarding Bonus Depreciation
On December 18, 2015, IP&L filed a formal challenge (“IP&L challenge”) with the FERC against ITC Midwest on certain inputs to ITC Midwest’s formula rates. The IP&L challenge alleged that ITC Midwest has unreasonably and imprudently opted out of using bonus depreciation in the calculation of its federal income tax expense and thereby unduly increased the transmission charges for transmission service to customers. On March 11, 2016, the FERC granted the IP&L challenge in part by requiring ITC Midwest to recalculate its revenue requirements, effective January 1, 2015, to simulate the election of bonus depreciation for 2015. The FERC denied IP&L’s request that ITC Midwest be required to elect bonus depreciation in any past or future years; however, stakeholders will be able to challenge any decision by ITC Midwest not to take bonus depreciation in future years. On June 8, 2016, the FERC denied ITC Midwest’s request for rehearing of the March 11, 2016 order. On August 3, 2016, ITC Midwest filed a petition for review of the FERC’s March 11, 2016 and June 8, 2016 orders in the United States Court of Appeals, District of Columbia Circuit. On September 8, 2016, ITC Midwest filed a motion to defer the petition pending the resolution of a private letter ruling matter from the IRS. In a separate but related matter, on April 15, 2016, Consumers Energy filed a formal challenge, or in the alternative, a complaint under Section 206 of the FPA, with the FERC against METC relating to METC’s historical practice of opting out of using bonus depreciation. On July 8, 2016, the FERC denied Consumers Energy’s formal challenge and dismissed the complaint without prejudice.
These consolidated financial statements reflect the election of bonus depreciation for tax years 2015 and 2016 and the corresponding effects on 2016 revenue requirements for our Regulated Operating Subsidiaries. Additionally, as required by the March 11, 2016 FERC order, we have simulated the election of bonus depreciation for ITC Midwest’s 2015 revenue requirement and included the impact of the corresponding refund obligation in these consolidated financial statements. The total impact from reflecting the election of bonus depreciation as described above was lower revenues of $20 million and lower net income of approximately $12 million for the year ended December 31, 2016 as compared to the same period if bonus depreciation was not reflected. These matters also resulted in additional net deferred income tax liabilities of approximately $109 million and a corresponding income tax receivable of $12 million as of December 31, 2016, and income tax refunds of $128 million, which were received from the IRS in August 2016. We are unable to predict the final outcome of this matter; however, the election of bonus depreciation will result in higher cash flows in the year of the election and reduce our rate base and therefore decrease our revenues and net income over the tax lives of the eligible assets.
ITC Midwest’s Rate Discount
As part of the orders by the Iowa Utility Board and the Minnesota Public Utilities Commission approving ITC Midwest’s acquisition of the IP&L transmission assets, ITC Midwest agreed to provide a rate discount of $4 million per year to its customers for eight years, beginning in the first year customers experience an increase in transmission


64

charges following the consummation of the ITC Midwest asset acquisition. From 2009 through 2016, ITC Midwest’s net revenue requirement was reduced by $4 million for each year. The rate discount is recognized in revenues when we provide the service and charge the reduced rate that includes the rate discount.
6.    REGULATORY ASSETS AND LIABILITIES
Regulatory Assets
The following table summarizes the regulatory asset balances at December 31, 2016 and 2015:
(In millions)
2016
 
2015
Regulatory Assets:
 
 
 
Current:
 
 
 
Revenue accruals (including accrued interest of less than $1 as of December 31, 2016 and 2015) (a)
$
24

 
$
15

ITCTransmission regional cost allocation recovery (including accrued interest of less than $1 as of December 31, 2016) (b)
29

 
—

Total current
53

 
15

Non-current:
 
 
 
Revenue accruals (including accrued interest of less than $1 as of December 31, 2016 and 2015) (a)
16

 
26

ITCTransmission ADIT Deferral (net of accumulated amortization of $42 and $39 as of December 31, 2016 and 2015, respectively)
19

 
22

METC ADIT Deferral (net of accumulated amortization of $24 and $22 as of December 31, 2016 and 2015, respectively)
19

 
21

METC Regulatory Deferrals (net of accumulated amortization of $7 as of December 31, 2016 and 2015)
8

 
8

Income taxes recoverable related to AFUDC equity
124

 
103

ITC Great Plains start-up, development and pre-construction
11

 
13

Pensions and postretirement
25

 
19

Income taxes recoverable related to implementation of the Michigan Corporate Income Tax
9

 
9

Accrued asset removal costs
16

 
12

Total non-current
247

 
233

 
 
 
 
Total
$
300

 
$
248

____________________________
(a)
Refer to discussion of revenue accruals in Note 5 under “Cost-Based Formula Rates with True-Up Mechanism.” Our Regulated Operating Subsidiaries do not earn a return on the balance of these regulatory assets, but do accrue interest carrying costs, which are subject to rate recovery along with the principal amount of the revenue accrual.
(b)
Refer to discussion of ITCTransmission regional cost allocation recovery in Note 5 under “ITCTransmission Regional Cost Allocation Refund.”
ITCTransmission ADIT Deferral
The carrying amount of the ITCTransmission Accumulated Deferred Income Tax (“ADIT”) Deferral is the remaining unamortized balance of the portion of ITCTransmission’s purchase price in excess of the fair value of net assets acquired approved for inclusion in future rates by the FERC. ITCTransmission earns a return on the remaining unamortized balance of this regulatory asset that is included in rate base. The original amount recorded for this regulatory asset of $61 million is recognized in rates and amortized on a straight-line basis over 20 years. ITCTransmission recorded amortization expense of $3 million annually during 2016, 2015 and 2014, which is included in depreciation and amortization and recovered through ITCTransmission’s cost-based formula rate template.


65

METC ADIT Deferral
The carrying amount of the METC ADIT Deferral is the remaining unamortized balance of the portion of METC’s purchase price in excess of the fair value of net assets acquired from Consumers Energy approved for inclusion in future rates by the FERC. The original amount recorded for this regulatory asset of $43 million is recognized in rates and amortized on a straight-line basis over 18 years beginning January 1, 2007. METC earns a return on the remaining unamortized balance of this regulatory asset that is included in rate base. METC recorded amortization expense of $2 million annually during 2016, 2015 and 2014, which is included in depreciation and amortization and recovered through METC’s cost-based formula rate template.
METC Regulatory Deferrals
METC has deferred, as a regulatory asset, depreciation and related interest expense associated with new transmission assets placed in service from January 1, 2001 through December 31, 2005 that were included on METC’s balance sheet at the time Michigan Transco Holdings, LLC (“MTH”) acquired METC from Consumers Energy (the “METC Regulatory Deferrals”). The original amount recorded for this regulatory asset of $15 million is recognized in rates and amortized over 20 years beginning January 1, 2007. METC earns a return on the remaining unamortized balance of this regulatory asset that is included in rate base. METC recorded amortization expense of $1 million annually during 2016, 2015 and 2014, which is included in depreciation and amortization and recovered through METC’s cost-based formula rate template.
Income Taxes Recoverable Related to AFUDC Equity
Accounting standards for income taxes provide that a regulatory asset be recorded if it is probable that a future increase in taxes payable, relating to the book depreciation of AFUDC equity that has been capitalized to property, plant and equipment, will be recovered from customers through future rates. The regulatory asset for the tax effects of AFUDC equity is recovered over the life of the underlying book asset in a manner that is consistent with the depreciation of the AFUDC equity that has been capitalized to property, plant and equipment. We do not earn a return on this regulatory asset and the related deferred tax liabilities do not reduce rate base.
ITC Great Plains Start-Up, Development and Pre-Construction
In 2013, ITC Great Plains made a filing with the FERC, under Section 205 of the FPA, to recover start-up, development and pre-construction expenses in future rates. These expenses included certain costs incurred by ITC Great Plains for two regional cost sharing projects in Kansas prior to construction. In March 2015, FERC accepted ITC Great Plains’ request to commence amortization of the authorized regulatory assets, subject to refund, and set the matter for hearing and settlement judge procedures. In December 2015, the FERC issued an order accepting an uncontested settlement agreement establishing the amounts of the regulatory assets and associated carrying charges to be recovered. The unamortized balance of these regulatory assets is included in rate base and amortized over a 10-year period, beginning in the second quarter of 2015. The amortization expense is recorded to general and administrative expenses and recovered through ITC Great Plains’ cost-based formula rate.
Pensions and Postretirement
Accounting standards for defined benefit pension and other postretirement plans for rate-regulated entities allow for amounts that otherwise would have been charged and/or credited to accumulated other comprehensive income (“AOCI”) to be recorded as a regulatory asset or liability. As the unrecognized amounts recorded to this regulatory asset are recognized, expenses will be recovered from customers in future rates under our cost based formula rates. Our Regulated Operating Subsidiaries do not earn a return on the balance of this regulatory asset.
Income Taxes Recoverable Related to Implementation of the Michigan Corporate Income Tax
In May 2011, the Michigan Business Tax (“MBT”) was repealed and replaced with the Michigan Corporate Income Tax (“CIT”), effective January 1, 2012. Under the CIT, we are taxed at a rate of 6.0% on federal taxable income attributable to our operations in the state of Michigan, subject to certain adjustments. In addition to the traditional income tax, the MBT had also included a modified gross receipts tax that allowed for deductions and credits for certain activities, none of which are part of the CIT. The change in Michigan tax law required us in 2011 to remove deferred income tax balances recognized under the MBT and establish new deferred income tax balances under the CIT, and the net result was incremental deferred state income tax liabilities at both ITCTransmission and METC. Under our cost-based formula rate, the future taxes receivable as a result of the tax law change has resulted


66

in the recognition of a regulatory asset, which will be collected from customers for the 23-year period and the 32-year period for ITCTransmission and METC, respectively, beginning in 2016. ITCTransmission and METC do not earn a return on the balance of this regulatory asset and the related net deferred tax liabilities do not reduce rate base.
Accrued Asset Removal Costs
The carrying amount of the accrued asset removal costs represents the difference between incurred costs to remove property, plant and equipment and the estimated removal costs included in rates. The portion of depreciation expense included in our depreciation rates related to asset removal costs reduces this regulatory asset and removal costs incurred are added to this regulatory asset. In addition, this regulatory asset has also been adjusted for timing differences between incurred costs to settle legal asset retirement obligations and the recognition of such obligations under the standards set forth by the FASB. Our Regulated Operating Subsidiaries include this item, excluding the cost component related to the recognition of our legal asset retirement obligations under the standards set forth by the FASB, as a reduction to accumulated depreciation for rate-making purposes, which is an increase to rate base.
Regulatory Liabilities
The following table summarizes the regulatory liability balances at December 31, 2016 and 2015:
(In millions)
2016
 
2015
Regulatory Liabilities:
 
 
 
Current:
 
 
 
Revenue deferrals (including accrued interest of less than $1 and $2 as of December 31, 2016 and 2015, respectively) (a)
$
9

 
$
37

Refund related to the formula rate template modifications (including accrued interest of $1 and less than $1 as of December 31, 2016 and 2015, respectively) (b)
2

 
8

Estimated refund related to return on equity complaint (including accrued interest of $9 as of December 31, 2016) (c)
118

 
—

Total current
129

 
45

Non-current:
 
 
 
Revenue deferrals (including accrued interest of $1 and less than $1 as of December 31, 2016 and 2015, respectively) (a)
32

 
6

Accrued asset removal costs
68

 
70

Refund related to the formula rate template modifications (including accrued interest of less than $1 as of December 31, 2015) (b)
—

 
2

Estimated potential refund related to return on equity complaints (including accrued interest of $6 as of December 31, 2016 and 2015) (c)
140

 
168

Excess state income tax deductions
9

 
9

Total non-current
249

 
255

 
 
 
 
Total
$
378

 
$
300

____________________________
(a)
Refer to discussion of revenue deferrals in Note 5 under “Cost-Based Formula Rates with True-Up Mechanism.” Our Regulated Operating Subsidiaries accrue interest on the true-up amounts which will be refunded through rates along with the principal amount of revenue deferrals in future periods.
(b)
Refer to discussion of the refund in Note 5 under “MISO Formula Rate Template Modifications Filing.”
(c)
Refer to discussion of the estimated refund and potential refund in Note 15 under “Rate of Return on Equity Complaints.”
Accrued Asset Removal Costs
The carrying amount of the accrued asset removal costs represents the difference between incurred costs to remove property, plant and equipment and the estimated removal costs included in rates. The portion of depreciation expense included in our depreciation rates related to asset removal costs is added to this regulatory liability and


67

removal expenditures incurred are charged to this regulatory liability. Our Regulated Operating Subsidiaries include this item within accumulated depreciation for rate-making purposes, which is a reduction to rate base.
Excess State Income Tax Deductions
We have taken income tax deductions associated with property additions that exceed the tax basis of property, and the unrealized income tax benefits resulting from these deductions are expected to be refunded to customers through future rates when the income tax benefits are realized. This regulatory liability and the related deferred tax assets do not affect rate base.
7.    GOODWILL AND INTANGIBLE ASSETS
Goodwill
At December 31, 2016 and 2015, we had goodwill balances recorded at ITCTransmission, METC and ITC Midwest of $173 million, $454 million and $323 million, respectively, which resulted from the ITCTransmission and METC acquisitions and ITC Midwest’s acquisition of the IP&L transmission assets, respectively.
Intangible Assets
Pursuant to the METC acquisition in October 2006, we have identified intangible assets with finite lives derived from the portion of regulatory assets recorded on METC’s historical FERC financial statements that were not recorded on METC’s historical GAAP financial statements associated with the METC Regulatory Deferrals and the METC ADIT Deferral. The carrying amounts of the intangible asset for the METC Regulatory Deferrals and the METC ADIT Deferral were $20 million and $8 million, respectively, as of December 31, 2016, and $22 million and $9 million, respectively, as of December 31, 2015. The amortization periods for the METC Regulatory Deferrals and the METC ADIT Deferral are 20 years and 18 years, respectively, beginning January 1, 2007. METC earns an equity return on the remaining unamortized balance of both intangible assets and recovers the amortization expense through METC’s cost-based formula rate template.
ITC Great Plains has recorded intangible assets for payments made by and obligations of ITC Great Plains to certain TOs to acquire rights, which are required under the SPP tariff to designate ITC Great Plains to build, own and operate projects within the SPP region, including two regional cost sharing projects in Kansas. The carrying amount of these intangible assets was $15 million and $14 million (net of accumulated amortization of $1 million and $1 million, respectively) as of December 31, 2016 and 2015, respectively. The amortization period for these intangible assets is 50 years.
During each of the years ended December 31, 2016, 2015 and 2014, we recognized $3 million of amortization expense of our intangible assets. We expect the annual amortization of our intangible assets that have been recorded as of December 31, 2016 to be as follows:
(In millions)
 
2017
$
3

2018
3

2019
3

2020
3

2021
3

2022 and thereafter
28

Total
$
43



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8.    PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment — net consisted of the following at December 31, 2016 and 2015:
(In millions)
2016
 
2015
Property, plant and equipment
 
 
 
Regulated Operating Subsidiaries:
 
 
 
Property, plant and equipment in service
$
7,715

 
$
7,086

Construction work in progress
455

 
426

Capital equipment inventory
74

 
55

Other
15

 
13

ITC Holdings and other
14

 
18

Total
8,273

 
7,598

Less: Accumulated depreciation and amortization
(1,575
)
 
(1,488
)
Property, plant and equipment — net
$
6,698

 
$
6,110

Additions to property, plant and equipment in service and construction work in progress during 2016 and 2015 were due primarily for projects to upgrade or replace existing transmission plant to improve the reliability of our transmission systems as well as transmission infrastructure to support generator interconnections and investments that provide regional benefits such as our Multi-Value Projects.


69

9.    DEBT
The following amounts were outstanding at December 31, 2016 and 2015:
(Amounts in millions)
2016
 
2015
ITC Holdings 5.875% Senior Notes, due September 30, 2016 (a)
$
—

 
$
139

ITC Holdings 6.23% Senior Notes, Series B, due September 20, 2017 (a)
50

 
50

ITC Holdings 6.375% Senior Notes, due September 30, 2036
200

 
200

ITC Holdings 6.05% Senior Notes, due January 31, 2018
385

 
385

ITC Holdings 5.50% Senior Notes, due January 15, 2020
200

 
200

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

 
250

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

 
400

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

 
300

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

 
—

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

 
161

ITC Holdings Revolving Credit Agreement, due March 28, 2019
73

 
138

ITC Holdings Commercial Paper Program (a)
145

 
95

ITCTransmission 6.125% First Mortgage Bonds, Series C, due March 31, 2036
100

 
100

ITCTransmission 5.75% First Mortgage Bonds, Series D, due April 1, 2018
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 Revolving Credit Agreement, due March 28, 2019
44

 
48

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

 
—

METC Term Loan Credit Agreement, due December 7, 2018
—

 
200

METC Revolving Credit Agreement, due March 28, 2019
31

 
3

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

 
175

ITC Midwest 7.12% First Mortgage Bonds, Series B, due December 22, 2017 (a)
40

 
40

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

 
35

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

 
75

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

 
100

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

 
100

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

 
225

ITC Midwest Revolving Credit Agreement, due March 28, 2019
127

 
72

ITC Great Plains 4.16% First Mortgage Bonds, Series A, due November 26, 2044
150

 
150

ITC Great Plains Revolving Credit Agreement, due March 28, 2019
59

 
59

Total principal
4,624

 
4,460

Unamortized deferred financing fees and discount
(34
)
 
(31
)
Total debt
$
4,590

 
$
4,429

____________________________
(a)
As of December 31, 2016 and 2015, there was $235 million and $395 million, respectively, of debt included within debt maturing within one year that is classified as a current liability in the consolidated statements of financial position.


70

The annual maturities of debt as of December 31, 2016 are as follows:
(In millions)
 
 
2017
 
$
235

2018
 
485

2019
 
334

2020
 
235

2021
 
—

2022 and thereafter
 
3,335

Total
 
$
4,624

ITC Holdings
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, 2016, ITC Holdings had approximately $145 million of commercial paper issued and outstanding under the program, with a weighted-average interest rate of 1.0% and weighted average remaining days to maturity of 7 days. The proceeds from issuances under the program during the year ended December 31, 2016 were used to repay and retire the $139 million of ITC Holdings’ 5.875% Senior Notes, due September 30, 2016, and for general corporate purposes, including the repayment of borrowings under ITC Holdings’ revolving credit agreement. The amount outstanding as of December 31, 2016 was classified as debt maturing within one year in the consolidated statements of financial position.
Unsecured Notes
On July 5, 2016, ITC Holdings issued $400 million aggregate principal amount of unsecured 3.25% Notes, due June 30, 2026. The proceeds from the issuance were used to repay the $161 million outstanding under ITC Holdings’ term loan credit agreement and for general corporate purposes, primarily the repayment of indebtedness outstanding under ITC Holdings’ commercial paper program discussed above. These Notes were issued under ITC Holdings’ indenture, dated April 18, 2013.
METC
Senior Secured Notes
On April 26, 2016, METC issued $200 million of 3.90% Senior Secured Notes, due April 26, 2046. The proceeds were used to repay the $200 million borrowed under METC’s term loan credit agreement discussed below. The METC Senior Secured Notes were issued under its first mortgage indenture and secured by a first mortgage lien on substantially all of its real property and tangible personal property.
Term Loan Credit Agreement
On December 8, 2015, METC entered into an unsecured, unguaranteed term loan credit agreement due December 7, 2018, under which METC borrowed $200 million. The proceeds were used to repay the $175 million of 5.75% Senior Secured Notes, due December 10, 2015, and for general corporate purposes. This borrowing was repaid in full as of December 31, 2016. The weighted-average interest rate throughout the life of the loan was 1.4%.
ITC Midwest
On April 7, 2015, ITC Midwest issued $225 million aggregate principal amount of 3.83% First Mortgage Bonds, Series G, due April 7, 2055. The proceeds from the issuance were used for general corporate purposes, including the repayment of borrowings under ITC Midwest’s revolving credit agreement. ITC Midwest’s First Mortgage Bonds are issued under its first mortgage and deed of trust and secured by a first mortgage lien on substantially all of its property.
Derivative Instruments and Hedging Activities
We may use derivative financial instruments, including interest rate swap contracts, to manage our exposure to fluctuations in interest rates. The use of these financial instruments mitigates exposure to these risks and the


71

variability of our operating results. We are not a party to leveraged derivatives and do not enter into derivative financial instruments for trading or speculative purposes. The interest rate swaps listed below manage interest rate risk associated with the forecasted future issuance of fixed-rate debt related to the expected refinancing of the maturing ITC Holdings 6.05% Senior Notes, due January 31, 2018. As of December 31, 2016, ITC Holdings had $385 million outstanding under the 6.05% Senior Notes.
Interest Rate Swaps
(In millions, except percentages)
 
Notional Amount
 
Weighted Average Fixed Rate
 
Original Term
 
Effective Date
July 2016 swaps
 
$
75

 
1.616
%
 
10 years
 
January 2018
August 2016 swap
 
25

 
1.599
%
 
10 years
 
January 2018
Total
 
$
100

 
 
 
 
 
 
The 10-year term interest rate swaps call for ITC Holdings to receive interest quarterly at a variable rate equal to LIBOR and pay interest semi-annually at various fixed rates effective for the 10-year period beginning January 31, 2018, after the agreements have been terminated. The agreements include a mandatory early termination provision and will be terminated no later than the effective date of the interest rate swaps of January 31, 2018. The interest rate swaps have been determined to be highly effective at offsetting changes in the fair value of the forecasted interest cash flows associated with the expected debt issuance, resulting from changes in benchmark interest rates from the trade date of the interest rate swaps to the issuance date of the debt obligation.
The interest rate swaps qualify for cash flow hedge accounting treatment, whereby any gain or loss recognized from the trade date to the effective date for the effective portion of the hedge is recorded net of tax in AOCI. This amount will be accumulated and amortized as a component of interest expense over the life of the forecasted debt. As of December 31, 2016, the fair value of the derivative instruments was an asset of $8 million. None of the interest rate swaps contain credit-risk-related contingent features. Refer to Note 12 for additional fair value information.
In June 2016, we terminated $300 million of 10-year interest rate swap contracts that managed the interest rate risk associated with the unsecured Notes issued by ITC Holdings described below. A summary of the terminated interest rate swaps is provided below:
Interest Rate Swaps
(In millions, except percentages)
 
Amount
 
Weighted Average
Fixed Rate of
 Interest Rate Swaps
 
Comparable
Reference Rate
of Notes
 
Loss on
Derivatives
 
Settlement
Date
10-year interest rate swaps
 
$
300

 
1.99%
 
1.37%
 
$
17

 
June 2016
The interest rate swaps qualified for cash flow hedge accounting treatment and the loss of $17 million was recognized in June 2016 for the effective portion of the hedges and recorded net of tax in AOCI. This amount is being amortized as a component of interest expense over the life of the related debt. The ineffective portion of the hedges was recognized in the consolidated statement of operations for the year ended December 31, 2016 and was not material.
Revolving Credit Agreements
At December 31, 2016, ITC Holdings and certain of its Regulated Operating Subsidiaries had the following unsecured revolving credit facilities available:
(Amounts in millions, except percentages)
Total
Available
Capacity
 
Outstanding
Balance (a)
 
Unused
Capacity
 
Weighted Average
Interest Rate on
Outstanding Balance
 
Commitment
Fee Rate (b)
ITC Holdings
$
400

 
$
73

 
$
327

(c)
 
2.0%
(d)
 
0.175
%
ITCTransmission
100

 
44

 
56

 
 
1.7%
(e)
 
0.10
%
METC
100

 
31

 
69

 
 
1.7%
(e)
 
0.10
%
ITC Midwest
250

 
127

 
123

 
 
1.7%
(e)
 
0.10
%
ITC Great Plains
150

 
59

 
91

 
 
1.7%
(e)
 
0.10
%
Total
$
1,000

 
$
334

 
$
666

 
 
 
 
 
 


72

____________________________
(a)
Included within long-term debt.
(b)
Calculation based on the average daily unused commitments, subject to adjustment based on the borrower’s credit rating.
(c)
ITC Holdings’ revolving credit agreement may be used for general corporate purposes, including to repay commercial paper issued pursuant to the commercial paper program described above, if necessary. While outstanding commercial paper does not reduce available capacity under ITC Holdings’ revolving credit agreement, the unused capacity under this agreement adjusted for the commercial paper outstanding was $182 million as of December 31, 2016.
(d)
Loan bears interest at a rate equal to LIBOR plus an applicable margin of 1.25% or at a base rate, which is defined as the higher of the prime rate, 0.50% above the federal funds rate or 1.00% above the one month LIBOR, plus an applicable margin of 0.25%, subject to adjustments based on ITC Holdings’ credit rating.
(e)
Loans bear interest at a rate equal to LIBOR plus an applicable margin of 1.00% or at a base rate, which is defined as the higher of the prime rate, 0.50% above the federal funds rate or 1.00% above the one month LIBOR, subject to adjustments based on the borrower’s credit rating.
On April 7, 2016, each of the unsecured revolving credit agreements described above was amended to allow for the consummation of the Merger.
Covenants
Our debt instruments contain numerous financial and operating covenants that place significant restrictions on certain transactions, such as incurring additional indebtedness, engaging in sale and lease-back transactions, creating liens or other encumbrances, entering into mergers, consolidations, liquidations or dissolutions, creating or acquiring subsidiaries, selling or otherwise disposing of all or substantially all of our assets and paying dividends. In addition, the covenants require us to meet certain financial ratios, such as maintaining certain debt to capitalization ratios and maintaining certain interest coverage ratios. As of December 31, 2016, we were not in violation of any debt covenant.
10.    INCOME TAXES
Our effective tax rate varied from the statutory federal income tax rate due to differences between the book and tax treatment of various transactions as follows:
(In millions)
2016
 
2015
 
2014
Income tax expense at 35% statutory rate
$
120

 
$
134

 
$
138

State income taxes (net of federal benefit)
3

 
14

 
16

AFUDC equity
(11
)
 
(8
)
 
(6
)
Excess tax deductions for share-based compensation (a)
(23
)
 
—

 
—

Other — net
8

 
2

 
2

Total income tax provision
$
97

 
$
142

 
$
150

____________________________
(a)
Amount relates to a federal income tax benefit for excess tax deductions generated in 2016 as a result of adopting the new accounting guidance associated with share-based payments as described in Note 3.
Components of the income tax provision were as follows:
(In millions)
2016
 
2015
 
2014
Current income tax (benefit) expense (a)
$
(122
)
 
$
65

 
$
60

Deferred income tax expense (b)(c)
219

 
77

 
90

Total income tax provision
$
97

 
$
142

 
$
150



73

____________________________
(a)
Amount for the year ended December 31, 2016 primarily relates to the cash benefit that resulted from the election of bonus depreciation as described in Note 5.
(b)
During the fourth quarter of 2016, we recognized total income tax benefits of $27 million for excess tax deductions for the year ended December 31, 2016 as a result of adopting the new accounting guidance associated with share-based payments as described in Note 3.
(c)
Amount for the year ended December 31, 2016 includes utilization of $126 million of net operating losses, primarily resulting from the election of bonus depreciation as described in Note 5.
Deferred tax assets and liabilities are recognized for the estimated future tax effect of temporary differences between the tax basis of assets or liabilities and the reported amounts in the financial statements.
Deferred income tax assets (liabilities) consisted of the following at December 31:
(In millions)
2016
 
2015
Property, plant and equipment
$
(1,026
)
 
$
(679
)
Federal income tax NOLs and other credits
140

 
1

METC regulatory deferral (a)
(11
)
 
(12
)
Acquisition adjustments — ADIT deferrals (a)
(15
)
 
(15
)
Goodwill
(163
)
 
(148
)
ITCTransmission regional cost allocation recovery (a)
(11
)
 
—

Refund liabilities (a)
56

 
70

Pension and postretirement liabilities
23

 
19

State income tax NOLs (net of federal benefit) (b)
47

 
20

Share-based compensation
—

 
14

Other — net (c)
(4
)
 
(5
)
Net deferred tax liabilities
$
(964
)
 
$
(735
)
Gross deferred income tax liabilities
$
(1,252
)
 
$
(888
)
Gross deferred income tax assets
288

 
153

Net deferred tax liabilities
$
(964
)
 
$
(735
)
____________________________
(a)
Described in Note 6.
(b)
During the fourth quarter of 2016, we recorded a deferred tax asset of $9 million for state income tax net operating losses, related to excess tax benefits generated in periods prior to 2016 that had not been previously recognized in the consolidated statements of financial position, upon adoption of the accounting guidance associated with share-based payments as described in Note 3.
(c)
Includes net revenue accruals and deferrals, including accrued interest, of $1 million as of December 31, 2016 and 2015.
We have federal income tax net operating losses (“NOLs”) and capital losses as of December 31, 2016, both of which we expect to use prior to their expirations starting in 2036 and 2018, respectively. We also have state income tax NOLs as of December 31, 2016, all of which we expect to use prior to their expiration starting in 2022.
11.    RETIREMENT BENEFITS AND ASSETS HELD IN TRUST
Pension Plan Benefits
We have a qualified defined benefit pension plan (“retirement plan”) for eligible employees, comprised of a traditional final average pay plan and a cash balance plan. The traditional final average pay plan is noncontributory, covers select employees and provides retirement benefits based on years of benefit service, average final compensation and age at retirement. The cash balance plan is also noncontributory, covers substantially all employees and provides retirement benefits based on eligible compensation and interest credits. Our funding practice for the retirement plan is to contribute amounts necessary to meet the minimum funding requirements of the Employee


74

Retirement Income Security Act of 1974, plus additional amounts as we determine appropriate. We made contributions of $3 million, $4 million and $4 million to the retirement plan in 2016, 2015 and 2014, respectively. We expect to contribute $3 million to the retirement plan in 2017.
We also have two supplemental nonqualified, noncontributory, defined benefit pension plans for selected management employees (the “supplemental benefit plans” and collectively with the retirement plan, the “pension plans”). The supplemental benefit plans provide for benefits that supplement those provided by the retirement plan. The obligations under these supplemental benefit plans are included in the pension benefit obligation calculations below. The investments held in trust for the supplemental benefit plans of $42 million and $36 million at December 31, 2016 and 2015, respectively, are not included in the plan asset amounts presented below, but are included in other assets on our consolidated statement of financial position. For the years ended December 31, 2016, 2015 and 2014, we contributed $5 million, $9 million and $5 million, respectively, to these supplemental benefit plans.
Our investments held for the supplemental benefit plans are classified as available-for-sale securities and the life-to-date net unrealized loss of less than $1 million as of December 31, 2016 and December 31, 2015 was recognized in AOCI.
The plan assets of the retirement plan consisted of the following assets by category:
Asset Category
2016
 
2015
Fixed income securities
50.3
%
 
50.4
%
Equity securities
49.7
%
 
49.6
%
Total
100.0
%
 
100.0
%
Net periodic benefit cost for the pension plans during 2016, 2015 and 2014 was as follows by component:
(In millions)
2016
 
2015
 
2014
Service cost
$
6

 
$
6

 
$
5

Interest cost
4

 
4

 
4

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

 
4

 
2

Net pension cost
$
10

 
$
11

 
$
7

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


75

The following table reconciles the obligations, assets and funded status of the pension plans as well as the presentation of the funded status of the pension plans in the consolidated statements of financial position as of December 31, 2016 and 2015:
(In millions)
2016
 
2015
Change in Benefit Obligation:
 
 
 
Beginning projected benefit obligation
$
(97
)
 
$
(96
)
Service cost
(6
)
 
(6
)
Interest cost
(4
)
 
(4
)
Actuarial net (loss) gain
(11
)
 
6

Benefits paid
2

 
3

Ending projected benefit obligation
$
(116
)
 
$
(97
)
Change in Plan Assets:
 
 
 
Beginning plan assets at fair value
$
58

 
$
56

Actual return on plan assets
5

 
—

Employer contributions
3

 
4

Benefits paid
(2
)
 
(2
)
Ending plan assets at fair value
$
64

 
$
58

Funded status, underfunded
$
(52
)
 
$
(39
)
Accumulated benefit obligation:


 


Retirement plan
$
(56
)
 
$
(49
)
Supplemental benefit plans
(55
)
 
(41
)
Total accumulated benefit obligation
$
(111
)
 
$
(90
)
Amounts recorded as:
 
 


Funded Status:
 
 
 
Accrued pension liabilities
$
(52
)
 
$
(45
)
Other non-current assets
4

 
6

Other current liabilities
(4
)
 
—

Total
$
(52
)
 
$
(39
)
Unrecognized Amounts in Non-current Regulatory Assets:
 
 
 
Net actuarial loss
$
25

 
$
19

Total
$
25

 
$
19

The unrecognized amounts that otherwise would have been charged and/or credited to AOCI in accordance with the FASB guidance on accounting for retirement benefits are recorded as a regulatory asset on our consolidated statements of financial position as discussed in Note 6. The amounts recorded as a regulatory asset represent a net periodic benefit cost to be recognized in our operating income in future periods.
Actuarial assumptions used to determine the benefit obligation for the pension plans at December 31, 2016, 2015 and 2014 are as follows:
 
2016
 
2015
 
2014
Weighted average discount rate (a)
4.00%
 
4.26%
 
3.95%
Annual rate of salary increases
4.00%
 
4.00%
 
4.00%
____________________________
(a)
The prior year discount rate assumptions have been presented to conform to current year weighted average presentation.


76

Actuarial assumptions used to determine the benefit cost for the pension plans for the years ended December 31, 2016, 2015 and 2014 are as follows:
 
2016
 
2015
 
2014
Weighted average discount rate — service cost (a)
4.46%
 
3.95%
 
4.80%
Weighted average discount rate — interest cost (a)
3.62%
 
3.95%
 
4.80%
Annual rate of salary increases
4.00%
 
4.00%
 
4.00 - 6.00%
Expected long-term rate of return on plan assets
6.40%
 
6.70%
 
6.75%
____________________________
(a)
The prior year discount rate assumptions have been presented to conform to current year weighted average presentation.
At December 31, 2016, the projected benefit payments for the pension plans calculated using the same assumptions as those used to calculate the benefit obligation described above are as follows:
(In millions
 
2017
$
6

2018
6

2019
6

2020
7

2021
7

2022 through 2026
45

Investment Objectives and Fair Value Measurement
The general investment objectives of the retirement plan include maximizing the return within reasonable and prudent levels of risk and controlling administrative and management costs. The targeted asset allocation is weighted equally between equity and fixed income investments. Investment decisions are made by our retirement benefits board as delegated by our board of directors. Equity investments may include various types of U.S. and international equity securities, such as large-cap, mid-cap and small-cap stocks. Fixed income investments may include cash and short-term instruments, U.S. Government securities, corporate bonds, mortgages and other fixed income investments. No investments are prohibited for use in the retirement plan, including derivatives, but our exposure to derivatives currently is not material. We intend that the long-term capital growth of the retirement plan, together with employer contributions, will provide for the payment of the benefit obligations.
We determine our expected long-term rate of return on plan assets based on the current and expected target allocations of the retirement plan investments and considering historical and expected long-term rates of returns on comparable fixed income investments and equity investments.
The measurement of fair value is based on a three-tier hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. Changes in economic conditions or model-based valuation techniques may require the transfer of financial instruments from one fair value level to another. In such instances, the transfer is reported at the beginning of the reporting period. For the years ended December 31, 2016 and 2015, there were no transfers between levels.


77

The fair value measurement of the retirement plan assets as of December 31, 2016, was as follows:
 
Fair Value Measurements at Reporting Date Using
 
Quoted Prices in
 
Significant
 
Significant
 
Active Markets for
 
Other Observable
 
Unobservable
(In millions)
Identical Assets
 
Inputs
 
Inputs
 
(Level 1)
 
(Level 2)
 
(Level 3)
Financial assets measured on a recurring basis:
 
 
 
 
 
Mutual funds — U.S. equity securities
$
25

 
$
—

 
$
—

Mutual funds — international equity securities
7

 
—

 
—

Mutual funds — fixed income securities
32

 
—

 
—

Total
$
64

 
$
—

 
$
—

The fair value measurement of the retirement plan assets as of December 31, 2015, was as follows:
 
Fair Value Measurements at Reporting Date Using
 
Quoted Prices in
 
Significant
 
Significant
 
Active Markets for
 
Other Observable
 
Unobservable
(In millions)
Identical Assets
 
Inputs
 
Inputs
 
(Level 1)
 
(Level 2)
 
(Level 3)
Financial assets measured on a recurring basis:
 
 
 
 
 
Mutual funds — U.S. equity securities
$
24

 
$
—

 
$
—

Mutual funds — international equity securities
5

 
—

 
—

Mutual funds — fixed income securities
29

 
—

 
—

Total
$
58

 
$
—

 
$
—

The mutual funds consist primarily of publicly traded mutual funds and are recorded at fair value based on observable trades for identical securities in an active market.
Other Postretirement Benefits
We provide certain postretirement health care, dental and life insurance benefits for eligible employees. We contributed $7 million, $9 million and $6 million to the postretirement benefit plan in 2016, 2015 and 2014, respectively. We expect to contribute $9 million to the plan in 2017.
The plan assets consisted of the following assets by category:
Asset Category
2016
 
2015
Fixed income securities
50.3
%
 
50.0
%
Equity securities
49.7
%
 
50.0
%
Total
100.0
%
 
100.0
%

Net postretirement benefit plan cost for 2016, 2015 and 2014 was as follows by component:
(In millions)
2016
 
2015
 
2014
Service cost
$
7

 
$
8

 
$
6

Interest cost
3

 
3

 
2

Expected return on plan assets
(2
)
 
(2
)
 
(1
)
Amortization of unrecognized loss
—

 
1

 
—

Net postretirement cost
$
8

 
$
10

 
$
7

Prior to 2016, we measured service and interest costs for the postretirement benefit plan utilizing a single weighted-average discount rate derived from the yield curve used to measure the plan obligation. Beginning in 2016, we adopted a spot rate approach for measuring service and interest costs for the postretirement benefit plan whereby specific spot rates along the yield curve used to determine the benefit obligation are applied to the relevant projected cash flows. We believe the new approach provides a more precise measurement of our service and interest costs; therefore, we have accounted for this change prospectively as a change in accounting estimate. This change does


78

not affect the measurement of our total benefit obligation and it did not have a material impact on 2016 net postretirement benefit cost.
The following table reconciles the obligations, assets and funded status of the plan as well as the amounts recognized as accrued postretirement liability in the consolidated statements of financial position as of December 31, 2016 and 2015:
(In millions)
2016
 
2015
Change in Benefit Obligation:
 
 
 
Beginning accumulated postretirement obligation
$
(58
)
 
$
(58
)
Service cost
(7
)
 
(8
)
Interest cost
(3
)
 
(3
)
Actuarial net (loss) gain
(1
)
 
10

Benefits paid
1

 
1

Ending accumulated postretirement obligation
$
(68
)
 
$
(58
)
Change in Plan Assets:
 
 
 
Beginning plan assets at fair value
$
42

 
$
33

Actual return on plan assets
4

 
—

Employer contributions
7

 
9

Employer provided retiree premiums
—

 
1

Benefits paid
(1
)
 
(1
)
Ending plan assets at fair value
$
52

 
$
42

Funded status, underfunded
$
(16
)
 
$
(16
)
Amounts recorded as:
 
 
 
Funded Status:
 
 
 
Accrued postretirement liabilities
$
(16
)
 
$
(16
)
Total
$
(16
)
 
$
(16
)
Unrecognized Amounts in Non-current Regulatory Assets:
 
 
 
Net actuarial loss
$
—

 
$
—

Total
$
—

 
$
—

The unrecognized amounts that otherwise would have been charged and/or credited to AOCI in accordance with the FASB guidance on accounting for retirement benefits are recorded as a regulatory asset on our consolidated statements of financial position as discussed in Note 6. The amounts recorded as a regulatory asset represent a net periodic benefit cost to be recognized in our operating income in future periods. Our measurement of the accumulated postretirement benefit obligation as of December 31, 2016 and 2015 does not reflect the potential receipt of any subsidies under the Medicare Prescription Drug, Improvement and Modernization Act of 2003.
Actuarial assumptions used to determine the benefit obligation at December 31, 2016, 2015 and 2014 are as follows:
 
2016
 
2015
 
2014
Discount rate
4.28%
 
4.62%
 
4.20%
Annual rate of salary increases
4.00%
 
4.00%
 
4.00%
Health care cost trend rate
7.00%
 
7.15%
 
7.25%
Ultimate health care cost trend rate
5.00%
 
5.00%
 
5.00%
Year that the ultimate trend rate is reached
2022
 
2022
 
2022
Annual rate of increase in dental benefit costs
5.00%
 
5.00%
 
5.00%


79

Actuarial assumptions used to determine the benefit cost for the years ended December 31, 2016, 2015 and 2014 are as follows:
 
2016
 
2015
 
2014
Discount rate — service cost
4.72%
 
4.20%
 
5.15%
Discount rate — interest cost
4.21%
 
4.20%
 
5.15%
Annual rate of salary increases
4.00%
 
4.00%
 
4.00%
Health care cost trend rate
7.15%
 
7.25%
 
7.50%
Ultimate health care cost trend rate
5.00%
 
5.00%
 
5.00%
Year that the ultimate trend rate is reached
2022
 
2022
 
2022
Expected long-term rate of return on plan assets
4.80%
 
5.20%
 
5.50%
At December 31, 2016, the projected benefit payments for the postretirement benefit plan calculated using the same assumptions as those used to calculate the benefit obligations listed above are as follows:
(In millions)
 
2017
$
1

2018
1

2019
1

2020
2

2021
2

2022 through 2026
14

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point increase or decrease in assumed health care cost trend rates would have the following effects on service and interest cost for 2016 and the postretirement benefit obligation at December 31, 2016:
 
One-Percentage-
 
One-Percentage-
(In millions)
Point Increase
 
Point Decrease
Effect on total of service and interest cost
$
3

 
$
(2
)
Effect on postretirement benefit obligation
15

 
(11
)
Investment Objectives and Fair Value Measurement
The general investment objectives of the other postretirement benefit plan include maximizing the return within reasonable and prudent levels of risk and controlling administrative and management costs. The targeted asset allocation is weighted equally between equity and fixed income investments. Investment decisions are made by our retirement benefits board as delegated by our board of directors. Equity investments may include various types of U.S. and international equity securities, such as large-cap, mid-cap and small-cap stocks. Fixed income investments may include cash and short-term instruments, U.S. Government securities, corporate bonds, mortgages and other fixed income investments. No investments are prohibited for use in the other postretirement benefit plan, including derivatives, but our exposure to derivatives currently is not material. We intend that the long-term capital growth of the other postretirement benefit plan, together with employer contributions, will provide for the payment of the benefit obligations.
We determine our expected long-term rate of return on plan assets based on the current target allocations of the retirement plan investments as well as consider historical returns on comparable fixed income investments and equity investments.
The measurement of fair value is based on a three-tier hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. Changes in economic conditions or model-based valuation techniques may require the transfer of financial instruments from one fair value level to another. In such instances, the transfer is reported at the beginning of the reporting period. For the years ended December 31, 2016 and 2015, there were no transfers between levels.


80

The fair value measurement of the other postretirement benefit plan assets as of December 31, 2016, was as follows:
 
Fair Value Measurements at Reporting Date Using
 
Quoted Prices in
 
Significant
 
Significant
 
Active Markets for
 
Other Observable
 
Unobservable
(In millions)
Identical Assets
 
Inputs
 
Inputs
 
(Level 1)
 
(Level 2)
 
(Level 3)
Financial assets measured on a recurring basis:
 
 
 
 
 
Mutual funds — U.S. equity securities
$
25

 
$
—

 
$
—

Mutual funds — international equity securities
1

 
—

 
—

Mutual funds — fixed income securities
26

 
—

 
—

Total
$
52

 
$
—

 
$
—

The fair value measurement of the other postretirement benefit plan assets as of December 31, 2015, was as follows:
 
Fair Value Measurements at Reporting Date Using
 
Quoted Prices in
 
Significant
 
Significant
 
Active Markets for
 
Other Observable
 
Unobservable
(In millions)
Identical Assets
 
Inputs
 
Inputs
 
(Level 1)
 
(Level 2)
 
(Level 3)
Financial assets measured on a recurring basis:
 
 
 
 
 
Mutual funds — U.S. equity securities
$
20

 
$
—

 
$
—

Mutual funds — international equity securities
1

 
—

 
—

Mutual funds — fixed income securities
21

 
—

 
—

Total
$
42

 
$
—

 
$
—

Our mutual fund investments consist primarily of publicly traded mutual funds and are recorded at fair value based on observable trades for identical securities in an active market.
Defined Contribution Plan
We also sponsor a defined contribution retirement savings plan. Participation in this plan is available to substantially all employees. We match employee contributions up to certain predefined limits based upon eligible compensation and the employee’s contribution rate. The cost of this plan was $7 million, $5 million and $5 million in 2016, 2015 and 2014, respectively.
12.    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, 2016 and 2015, there were no transfers between levels.


81

Our assets and liabilities measured at fair value subject to the three-tier hierarchy at December 31, 2016, were as follows:
 
Fair Value Measurements at Reporting Date Using
(In millions)
Quoted Prices in
Active Markets for
Identical Assets
 
Significant
Other Observable
Inputs
 
Significant
Unobservable
Inputs
 
(Level 1)
 
(Level 2)
 
(Level 3)
Financial assets measured on a recurring basis:
 
 
 
 
 
Mutual funds — fixed income securities
$
42

 
$
—

 
$
—

Mutual funds — equity securities
1

 
—

 
—

Interest rate swap derivatives
—

 
8

 
—

Total
$
43

 
$
8

 
$
—

Our assets and liabilities measured at fair value subject to the three-tier hierarchy at December 31, 2015, were as follows:
 
Fair Value Measurements at Reporting Date Using
(In millions)
Quoted Prices in
Active Markets for
Identical Assets
 
Significant
Other Observable
Inputs
 
Significant
Unobservable
Inputs
 
(Level 1)
 
(Level 2)
 
(Level 3)
Financial assets measured on a recurring basis:
 
 
 
 
 
Mutual funds — fixed income securities
$
36

 
$
—

 
$
—

Mutual funds — equity securities
1

 
—

 
—

Financial liabilities measured on a recurring basis:
 
 
 
 
 
Interest rate swap derivatives
—

 
(3
)
 
—

Total
$
37

 
$
(3
)
 
$
—

As of December 31, 2016 and 2015, we held certain assets and liabilities 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 nonqualified, noncontributory, retirement benefit plans for selected management employees. Our mutual funds consist of publicly traded mutual funds 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. Gain and losses are recorded in earnings for investments classified as trading securities and AOCI for investments classified as available-for-sale.
The asset and liability related to derivatives consist of interest rate swaps as discussed in Note 9. The fair value of our interest rate swap derivatives is determined based on a discounted cash flow (“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, 2016 and 2015.
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 $4,306 million and $3,880 million at December 31, 2016 and 2015, 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


82

loan credit agreements and commercial paper, was $4,112 million and $3,654 million at December 31, 2016 and 2015, respectively.
Revolving and Term Loan Credit Agreements
At December 31, 2016 and 2015, we had a consolidated total of $334 million and $681 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.
13.    STOCKHOLDERS' EQUITY
Share-Based Payment
Restricted Stock Awards — On May 19, 2016, pursuant to the 2015 Long-Term Incentive Plan, we granted 453,219 shares of restricted stock. There were no additional share-based awards granted during 2016.
Merger — Under the Merger Agreement, outstanding options to acquire common stock of ITC Holdings vested immediately prior to closing and were converted into the right to receive the difference between the Merger consideration and the exercise price of each option in cash, restricted stock vested immediately prior to closing and was converted into the right to receive the Merger consideration in cash and performance shares vested immediately prior to closing at the higher of target or actual performance through the effective time of the Merger and were converted into the right to receive the Merger consideration in cash. The per share amount of Merger consideration determined in accordance with the Merger Agreement and used for purposes of settling the share-based awards was $45.72. For the year ended December 31, 2016, we recognized approximately $41 million of expense due to the accelerated vesting of the share-based awards that occurred at the completion of the Merger. Refer to Note 2 for additional discussion regarding the Merger. As of December 31, 2016, there were no outstanding share-based payment awards.
Share-Based Compensation — We recorded share-based compensation in 2016, 2015 and 2014 as follows:
(In millions)
2016
 
2015
 
2014
Operation and maintenance expenses
$
2

 
$
2

 
$
1

General and administrative expenses (a)
52

 
11

 
9

Amounts capitalized to property, plant and equipment
5

 
5

 
5

Total share-based compensation
$
59

 
$
18

 
$
15

Total tax benefit recognized in the consolidated statement of operations
$
49

 
$
5

 
$
4

____________________________
(a)
Amount for the year ended December 31, 2016 includes the expense recognized due to the accelerated vesting of the share-based awards upon completion of the Merger as described above.
Related Party Transactions
During the fourth quarter of 2016, we received $137 million from Investment Holdings for the cash settlement of the share-based awards that vested at the consummation of the Merger as described above. Additionally, we paid dividends of $33 million to Investment Holdings during the fourth quarter of 2016.


83

Accumulated Other Comprehensive Income
The following table provides the components of changes in AOCI for the years ended December 31, 2016, 2015 and 2014:
 
Year Ended December 31,
(In millions)
2016
 
2015
 
2014
Balance at the beginning of period
$
4

 
$
5

 
$
7

Reclassification of net loss relating to interest rate cash flow hedges from AOCI to interest expense — net (net of tax of $1 for the year ended December 31, 2016) (a)
1

 
—

 
—

Loss on interest rate swaps relating to interest rate cash flow hedges (net of tax of $2, $1 and $1 for the years ended December 31, 2016, 2015 and 2014, respectively)
(3
)
 
(1
)
 
(2
)
Total other comprehensive loss, net of tax (b)
(2
)
 
(1
)
 
(2
)
Balance at the end of period
$
2

 
$
4

 
$
5

____________________________
(a)
Includes reclassification of net loss relating to interest rate cash flow hedges from AOCI to interest expense, net of tax, of less than $1 million for the years ended December 31, 2015 and 2014.
(b)
Includes unrealized gains and losses on available-for-sale securities, net of tax, of less than $1 million for the years ended December 31, 2016, 2015 and 2014.
The amount of net loss relating to interest rate cash flow hedges to be reclassified from AOCI to interest expense for the 12-month period ending December 31, 2017 is expected to be $3 million.
14.    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. Our participating share of expenses associated with these jointly held assets are primarily recorded within operation and maintenance expenses on our consolidated statement of operations.
We have investments in jointly owned utility assets as shown in the table below as of December 31, 2016:

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

 
$
29

 
$
—

METC (c)
14

 
41

 
—

ITC Midwest (d)
18

 
35

 
3

ITC Great Plains (e)
10

 
22

 
—

Total
$
42

 
$
127

 
$
3

____________________________
(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. The municipal power agency’s ownership portion entitles them to approximately 234 MW of network transmission service from the ITCTransmission system. 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


84

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, 2016, METC’s ownership percentages for jointly owned substation facilities and lines ranged from 6.3% to 92.0% and 1.0% to 41.9%, respectively.
(d)
ITC Midwest has joint sharing of several substations and transmission lines with various parties. As of December 31, 2016, ITC Midwest had net investments in jointly owned substation assets under construction and jointly shared transmission lines of $2 million and $1 million, respectively. 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, 2016.
(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, 2016, ITC Great Plains’ ownership percentage in the project was 51.0%.
15.    COMMITMENTS AND CONTINGENT LIABILITIES
Environmental Matters
We are subject to federal, state and local environmental laws and regulations, which impose limitations on the discharge of pollutants into the environment, establish standards for the management, treatment, storage, transportation and disposal of solid and hazardous wastes and hazardous materials, and impose obligations to investigate and remediate contamination in certain circumstances. Liabilities relating to investigation and remediation of contamination, as well as other liabilities concerning hazardous materials or contamination, such as claims for personal injury or property damage, may arise at many locations, including formerly owned or operated properties and sites where wastes have been treated or disposed of, as well as properties currently owned or operated by us. Such liabilities may arise even where the contamination does not result from noncompliance with applicable environmental laws. Under some environmental laws, such liabilities may also be joint and several, meaning that a party can be held responsible for more than its share of the liability involved, or even the entire share. Although environmental requirements generally have become more stringent and compliance with those requirements more expensive, we are not aware of any specific developments that would increase our costs for such compliance in a manner that would be expected to have a material adverse effect on our results of operations, financial position or liquidity.
Our assets and operations also involve the use of materials classified as hazardous, toxic or otherwise dangerous. Many of the properties that we own or operate have been used for many years, and include older facilities and equipment that may be more likely than newer ones to contain or be made from such materials. Some of these properties include aboveground or underground storage tanks and associated piping. Some of them also include large electrical equipment filled with mineral oil, which may contain or previously have contained PCBs. Our facilities and equipment are often situated on or near property owned by others so that, if they are the source of contamination, others’ property may be affected. For example, aboveground and underground transmission lines sometimes traverse properties that we do not own and transmission assets that we own or operate are sometimes commingled at our transmission stations with distribution assets owned or operated by our transmission customers.
Some properties in which we have an ownership interest or at which we operate are, or are suspected of being, affected by environmental contamination. We are not aware of any pending or threatened claims against us with respect to environmental contamination relating to these properties, or of any investigation or remediation of contamination at these properties, that entail costs likely to materially affect us. Some facilities and properties are located near environmentally sensitive areas such as wetlands.


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Claims have been made or threatened against electric utilities for bodily injury, disease or other damages allegedly related to exposure to electromagnetic fields associated with electric transmission and distribution lines. While we do not believe that a causal link between electromagnetic field exposure and injury has been generally established and accepted in the scientific community, the liabilities and costs imposed on our business could be significant if such a relationship is established or accepted. We are not aware of any pending or threatened claims against us for bodily injury, disease or other damages allegedly related to exposure to electromagnetic fields and electric transmission and distribution lines that entail costs likely to have a material adverse effect on our results of operations, financial position or liquidity.
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.
Michigan Sales and Use Tax Audit
The Michigan Department of Treasury has conducted sales and use tax audits of ITCTransmission for the audit periods April 1, 2005 through June 30, 2008 and October 1, 2009 through September 30, 2013. The Michigan Department of Treasury has denied ITCTransmission’s claims of the industrial processing exemption from use tax that it has taken beginning January 1, 2007. The exemption claim denials resulted in use tax assessments against ITCTransmission. ITCTransmission filed administrative appeals to contest these use tax assessments.
In a separate, but related case involving a Michigan-based public utility that made similar industrial processing exemption claims, the Michigan Supreme Court ruled in July 2015 that the electric system, which involves altering voltage, constitutes an exempt, industrial processing activity. However, the ruling further held the electric system is also used for other functions that would not be exempt, and remanded the case to the Michigan Court of Claims to determine how the exemption applies to assets that are used in electric distribution activities. On March 30, 2016, ITCTransmission withdrew its administrative appeals, and subsequently filed a civil action in the Michigan Court of Claims seeking to have the use tax assessments at issue canceled. The discovery period for this litigation ended on December 5, 2016. On November 2, 2016, the Michigan Court of Claims denied a motion filed by the Michigan Department of Treasury for partial summary disposition of the ITCTransmission civil action. The Michigan Department of Treasury has appealed this denial with the Michigan Court of Appeals. The Court of Claims consolidated the ITCTransmission civil action with similar, pending litigation involving another company, and ordered both cases to mediation. Given the pending status of this litigation, ITCTransmission cannot estimate the timing of any potential tax assessments or refunds.
The amount of use tax associated with the exemptions taken by ITCTransmission through December 31, 2016 is estimated to be approximately $21 million, including interest. This amount includes approximately $11 million, including interest, assessed for the audit periods noted above. ITCTransmission believes it is probable that portions of the use tax assessments will be sustained upon resolution of this matter and has recorded $10 million and $6 million for this contingent liability, including interest, as of December 31, 2016 and 2015, respectively, primarily as an increase to property, plant and equipment, which is a component of revenue requirement in our cost-based formula rate.
METC has also taken the industrial processing exemption, estimated to be approximately $11 million for open periods. METC has not been assessed any use tax liability and has not recorded any contingent liability as of December 31, 2016 associated with this matter. In the event it becomes appropriate to record additional use tax liability relating to this matter, ITCTransmission and METC would record the additional use tax primarily as an increase to the cost of property, plant and equipment, as the majority of purchases for which the exemption was taken relate to equipment purchases associated with capital projects.
Rate of Return on Equity Complaints
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 a complaint with the FERC under Section 206 of the FPA (the “Initial Complaint”), requesting that the FERC find the then current


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12.38% MISO regional base ROE rate (the “base ROE”) for all MISO TOs, including ITCTransmission, METC and ITC Midwest, to no longer be just and reasonable. The complainants sought a FERC order reducing the base ROE used in the formula transmission rates for our MISO Regulated Operating Subsidiaries to 9.15%, reducing the equity component of our capital structure from the FERC approved 60% to 50% and terminating the ROE adders approved for certain ITC Holdings Regulated Operating Subsidiaries, including adders currently utilized by ITCTransmission and METC.
On June 19, 2014, in a separate Section 206 complaint against the regional base ROE rate for ISO New England TOs, the FERC adopted a new methodology for establishing base ROE rates for electric transmission utilities. The new methodology is based on a two-step DCF analysis that uses both short-term and long-term growth projections in calculating ROE rates for a proxy group of electric utilities. The previous methodology used only short-term growth projections. The FERC also reiterated that it can apply discretion in determining how ROE rates are established within a zone of reasonableness and reiterated its policy for limiting the overall ROE rate for any company, including the base and all applicable adders, at the high end of the zone of reasonableness set by the two-step DCF methodology. The new method presented in the ISO New England ROE case will be used in resolving the MISO ROE case.
On October 16, 2014, the FERC granted the complainants’ request in part by setting the base ROE for hearing and settlement procedures, while denying all other aspects of the Initial Complaint. The FERC also denied the request to terminate ITCTransmission’s and METC’s ROE incentives, subject to the top end of a zone of reasonableness. The FERC set the refund effective date for the Initial Complaint as November 12, 2013.
On December 22, 2015, the presiding administrative law judge issued an initial decision on the Initial Complaint. On September 28, 2016, the FERC issued an order (the “September 2016 Order”) affirming the presiding administrative law judge’s initial decision and setting the base ROE at 10.32%, with a maximum ROE of 11.35%, effective for the period from November 12, 2013 through February 11, 2015 (the “Initial Refund Period”). Additionally, the rates established by the September 2016 Order will be used prospectively from the date of that order until a new approved rate is established by the FERC in ruling on the Second Complaint described below, resulting in an ROE used currently by ITCTransmission, METC and ITC Midwest of 11.35%, 11.35% and 11.32%, respectively. The September 2016 Order requires all MISO TOs, including our MISO Regulated Operating Subsidiaries, to provide refunds within 30 days for the Initial Refund Period. The estimated refund for the Initial Complaint resulting from this FERC order, including interest, is $118 million for our MISO Regulated Operating Subsidiaries, recorded in current liabilities on the consolidated statements of financial position. On October 21, 2016, the MISO TOs, including our MISO Regulated Operating Subsidiaries, filed a request with the FERC for an extension of nine months, until July 28, 2017, to provide refunds, which was granted by the FERC on October 28, 2016. Additionally, on October 28, 2016, the MISO TOs, including our MISO Regulated Operating Subsidiaries, filed a request with the FERC for rehearing of the September 2016 Order regarding the future exclusion of certain short-term growth projections in the two-step DCF analysis used by FERC to determine the cost of equity of public utilities. On October 28, 2016, the complainants also filed a request with the FERC for rehearing, citing that FERC erred in several material respects in the September 2016 Order. The FERC issued a tolling order on November 28, 2016 to allow for additional time to address the rehearing requests. On February 14, 2017, our MISO Regulated Operating Subsidiaries provided $119 million to MISO to fund the payment of the refund, including interest, pursuant to the September 2016 Order.
On February 12, 2015, an additional complaint was filed with the FERC under Section 206 of the FPA (the “Second Complaint”) by 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 18, 2015, the FERC set the Second Complaint for hearing and settlement procedures. The FERC also set the refund effective date for the Second Complaint as February 12, 2015.
On June 30, 2016, the presiding administrative law judge issued an initial decision on the Second Complaint, which recommended a base ROE of 9.70% for February 12, 2015 through May 11, 2016 (the “Second Refund Period”), with a maximum ROE of 10.68%. The initial decision is a non-binding recommendation to the FERC on the Second Complaint, and all parties, including the MISO TOs and the complainants, have filed briefs contesting various parts of the proposed findings and recommendations. In resolving the Second Complaint, we expect the FERC to establish a new base ROE and zone of reasonable returns that will be used, along with any ROE adders,


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to calculate the refund liability for the Second Refund Period. We anticipate a FERC order on the Second Complaint in 2017. The timing of providing refunds for the Second Complaint is uncertain; however, we do not expect to provide refunds during 2017 for the Second Complaint and therefore, the associated refund liability is recorded in non-current liabilities on the consolidated statements of financial position.
In addition to the estimated refund for the Initial Complaint noted above, we believe it is probable that a refund will be required in connection with the Second Complaint. As of December 31, 2016, the estimated range of aggregate refunds for the Initial Refund Period and Second Refund Period is expected to be from $221 million to $258 million on a pre-tax basis. As of December 31, 2016, our MISO Regulated Operating Subsidiaries had recorded aggregate estimated regulatory liabilities totaling $258 million for the Initial Complaint and Second Complaint, representing the best estimate of the probable aggregate refunds based on the resolution of the Initial Complaint in the September 2016 Order. As of December 31, 2015, our MISO Regulated Operating Subsidiaries had recorded an aggregate estimated regulatory liability of $168 million, which represented the low end of the range of potential refunds as of that date, as there was no best estimate within the range of refunds at that time. The recognition of these estimated liabilities resulted in the following impacts to our consolidated results of operations:
 
Year Ended December 31,
(in millions)
2016
 
2015
 
2014
Increase (decrease) in:
 
 
 
 
 
Operating revenues
$
(80
)
 
$
(115
)
 
$
(47
)
Interest expense
10

 
5

 
1

Estimated net income (a)
(55
)
 
(73
)
 
(29
)
____________________________
(a)
Includes an effect on net income of $27 million, $28 million and $3 million for the year ended December 31, 2016, 2015 and 2014, respectively, for revenue initially recognized in 2015, 2014 and 2013.
It is possible the outcome of these matters could differ from the estimated range of losses and materially affect our consolidated results of operations due to the uncertainty of the calculation of an authorized base ROE along with the zone of reasonableness under the newly adopted two-step DCF methodology, which is subject to significant discretion by the FERC. As of December 31, 2016, our MISO Regulated Operating Subsidiaries had a total of approximately $3 billion of equity in their collective capital structures for ratemaking purposes. Based on this level of aggregate equity, we estimate that each 10 basis point reduction in the authorized ROE would reduce annual consolidated net income by approximately $3 million.
In a separate but related matter, in November 2014, METC, ITC Midwest and other MISO TOs filed a request with the FERC, under FPA Section 205, for authority to include a 50 basis point incentive adder for RTO participation in each of the TOs’ formula rates. On January 5, 2015, the FERC approved the use of this incentive adder, effective January 6, 2015. Additionally, ITC Midwest filed a request with the FERC, under FPA Section 205, in January 2015 for authority to include a 100 basis point incentive adder for independent transmission ownership, which is currently authorized for ITCTransmission and METC. On March 31, 2015, the FERC approved the use of a 50 basis point incentive adder for independence, effective April 1, 2015. On April 30, 2015, ITC Midwest filed a request with the FERC for rehearing on the approved incentive adder for independence and this request was subsequently denied by the FERC on January 6, 2016. An appeal of the FERC’s decision has been filed. Beginning September 28, 2016, these incentive adders have been applied to METC’s and ITC Midwest’s base ROEs in establishing their total authorized ROE rates, subject to the maximum ROE limitation in the September 2016 Order of 11.35%.
Challenges Regarding Bonus Depreciation
See “Challenges Regarding Bonus Depreciation” in Note 5 for discussion of these challenges.
Legal Matters Associated with the Merger
Following the announcement of the Merger, four putative state class action lawsuits were filed by purported shareholders of ITC Holdings on behalf of a purported class of ITC Holdings shareholders. Initially, the four actions (Paolo Guerra v. Albert Ernst, et al., Harvey Siegelman v. Joseph L. Welch, et al., Alan Poland v. Fortis Inc., et al., Sanjiv Mehrotra v. Joseph L. Welch, et al.) were filed in the Oakland County Circuit Court of the State of Michigan. The complaints name as defendants a combination of ITC Holdings and the individual members of the ITC Holdings board of directors, Fortis, FortisUS and Merger Sub. The complaints generally allege, among other things, that (1)


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ITC Holdings’ directors breached their fiduciary duties in connection with the Merger Agreement, (including, but not limited to, various alleged breaches of duties of good faith, loyalty, care and independence), (2) ITC Holdings’ directors failed to take appropriate steps to maximize shareholder value and claims that the Merger Agreement contains several deal protection provisions that are unnecessarily preclusive and (3) a combination of ITC Holdings, Fortis, FortisUS and Merger Sub aided and abetted the purported breaches of fiduciary duties. The complaints sought class action certification and a variety of relief including, among other things, enjoining defendants from completing the Merger, unspecified damages, and costs, including attorneys’ fees and expenses. The Siegelman case was voluntarily dismissed by the plaintiff on March 22, 2016. On March 23, 2016, the state court entered an order directing that the related cases be consolidated under the caption In re ITC Holdings Corporation Shareholder Litigation. On April 8, 2016, Poland filed an amended complaint to add derivative claims on behalf of ITC Holdings.
On March 14, 2016, the Guerra state court action was dismissed by the plaintiff and refiled in the United States District Court, Eastern District of Michigan, as Paolo Guerra v. Albert Ernst, et al. The federal complaint named the same defendants (plus FortisUS), asserted the same general allegations and sought the same types of relief as in the state court cases. On March 25, 2016, Guerra amended his federal complaint. The amended complaint dropped Fortis US, Fortis and Merger Sub as defendants and added claims alleging that the defendants violated Sections 14(a) and 20(a) of the Exchange Act because the preliminary proxy statement/prospectus, filed with the SEC in connection with the special meeting of shareholders to approve the Merger Agreement, was allegedly materially misleading and allegedly omitted material facts that were necessary to render it non-misleading.
Another lawsuit was filed on April 8, 2016 in the United States District Court, Eastern District of Michigan captioned Harold Severance v. Joseph L. Welch et al. against the individual members of the ITC Holdings board of directors, Fortis, FortisUS and Merger Sub, asserting the same general allegations and seeking the same type of relief as Guerra.
On April 22, 2016, the Mehrotra state court action was dismissed by the plaintiff and refiled in the United States District Court, Eastern District of Michigan, as Sanjiv Mehrotra v. Joseph L. Welch, et al. With the exception of Fortis, the federal complaint named the same defendants and asserted the same general allegations as the other federal complaints.
On June 8, 2016, the Oakland County Circuit Court of the State of Michigan denied a motion for summary disposition filed by ITC Holdings and the individual members of the ITC Holdings board of directors. ITC Holdings voluntarily made supplemental disclosures related to the Merger in response to certain allegations, which are set forth in a Form 8-K filed with the SEC on June 13, 2016. Nothing in those supplemental disclosures shall be deemed an admission of the legal necessity or materiality under applicable laws of any of the disclosures set forth therein.
On July 6, 2016, the federal actions were voluntarily dismissed by the federal plaintiffs. The federal plaintiffs reserved the right to make certain other claims, and ITC Holdings and the individual members of the ITC Holdings board of directors reserved the right to oppose any such claim. The federal plaintiffs have sought a mootness fee application and the parties are currently exploring a mutually satisfactory resolution.
On July 8, 2016, the plaintiffs in Poland filed a motion for class certification. On July 13, 2016, ITC Holdings and the individual members of the ITC Holdings board of directors filed their respective answers to the amended complaint in Poland. On July 19, 2016, the Poland state court issued a scheduling order, which, among other things, requires the parties to complete discovery by March 10, 2017, and sets a trial date for June 5, 2017. On July 25, 2016, the Poland state court issued an order allowing a new plaintiff, Washtenaw County Employees’ Retirement System, to intervene in the Poland case. On January 20, 2017, the defendants filed an additional motion for summary disposition, which is expected to be heard by the Poland state court in March 2017. A hearing on class certification was held on February 9, 2017.
We believe the remaining lawsuit is without merit and intend to vigorously defend against it. However, there can be no assurance that the outcome of this litigation will not have a material adverse effect on our results of operations, financial condition or cash flows. See Note 2 for additional discussion on the Merger.
Development Projects
We are pursuing strategic development projects that may result in us becoming obligated to make contingent payments to developers if the projects reach certain milestones. We believe it is reasonably possible that we will be required to make contingent development payments at a maximum amount of approximately $120 million from the period from 2017 through 2020. Based on the nature of the related agreements, it is expected that development


89

payments will be made at milestones that would indicate the project is financially viable. In the event it becomes probable that we will make these payments, we would recognize the liability and the corresponding intangible asset or expense as appropriate.
Purchase Obligations and Leases
At December 31, 2016, we had purchase obligations of $44 million representing commitments for materials, services and equipment that had not been received as of December 31, 2016, primarily for construction and maintenance projects for which we have an executed contract. The purchase obligations are expected to be paid in 2017, with the majority of the items related to materials and equipment that have long production lead times.
We have operating leases for office space, equipment and storage facilities. We recognize expenses relating to our operating lease obligations on a straight-line basis over the term of the lease. We recognized rent expense of $1 million for each of the years ended December 31, 2016, 2015 and 2014 recorded in general and administrative expenses as well as operation and maintenance expenses. These amounts and the amounts in the table below do not include any expense or payments to be made under the METC Easement Agreement described below under “Other Commitments — METC — Amended and Restated Easement Agreement with Consumers Energy.”
Future minimum lease payments under the leases at December 31, 2016 were:
(In millions)
 
2017
$
1

2018
1

2019
1

2020
1

2021 and thereafter
1

Total minimum lease payments
$
5

Other Commitments
METC
Amended and Restated Purchase and Sale Agreement for Ancillary Services with Consumers Energy. Under the Purchase and Sale Agreement for Ancillary Services with Consumers Energy (the “Ancillary Services Agreement”), Consumers Energy provides reactive power, balancing energy, load following and spinning and supplemental reserves that are needed by METC and MISO. These ancillary services are a necessary part of the provision of transmission service. This agreement is necessary because METC does not own any generating facilities and therefore must procure ancillary services from third party suppliers, including Consumers Energy. The Ancillary Services Agreement establishes the terms and conditions under which METC obtains ancillary services from Consumers Energy. Consumers Energy will offer all ancillary services as required by FERC Order No. 888 at FERC-approved rates. METC is not precluded from procuring these services from third party suppliers and is free to purchase ancillary services from unaffiliated generators located within its control area or neighboring jurisdictions on a non-preferential, competitive basis. This one-year agreement became effective on May 1, 2002 and is automatically renewed each year for successive one-year periods. The Ancillary Services Agreement can be terminated by either party with six months prior written notice. Services performed by Consumers Energy under the Ancillary Services Agreement are charged to operation and maintenance expenses.
Amended and Restated Easement Agreement with Consumers Energy. The Easement Agreement with Consumers Energy (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. Consumers Energy has reserved for itself the rights to other uses of the infrastructure (such as for fiber optics, telecommunications and gas pipelines), along with the value of activities associated with such uses. 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. 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 have entered into the Operations Services Agreement For 34.5 kV Transmission Facilities (the “OSA”), effective as of January 1,


90

2011, under which IP&L performs certain operations of ITC Midwest’s 34.5 kV transmission system. The OSA will remain in full force and effect until December 31, 2015 and will extend automatically from year to year thereafter until terminated by either party upon not less than one year prior written notice to the other party.
ITC Great Plains
Amended and Restated Maintenance Agreement. Mid-Kansas Electric Company LLC (“Mid-Kansas”) and ITC Great Plains have entered into a Maintenance Agreement (the “Mid-Kansas Agreement”), dated as of August 24, 2010, and most recently amended effective as of June 1, 2015, pursuant to which Mid-Kansas has agreed to perform various field operations and maintenance services related to certain ITC Great Plains assets. The Mid-Kansas Agreement has an initial term of 10 years and automatic 10-year renewal terms unless terminated (1) due to a breach by the non-terminating party following notice and failure to cure, (2) by mutual consent of the parties, or (3) by ITC Great Plains under certain limited circumstances. Services must continue to be provided for at least six months subsequent to the termination date in any case.
Concentration of Credit Risk
Our credit risk is primarily with DTE Electric, Consumers Energy and IP&L, which were responsible for approximately 20.7%, 21.7% and 25.5%, respectively, or $254 million, $267 million and $314 million, respectively, of our consolidated billed revenues for the year ended December 31, 2016. These percentages and amounts of total billed revenues of DTE Electric, Consumers Energy and IP&L include the collection of 2014 revenue accruals and deferrals and exclude any amounts for the 2016 revenue accruals and deferrals that were included in our 2016 operating revenues, but will not be billed to our customers until 2018. Any financial difficulties experienced by DTE Electric, Consumers Energy or IP&L 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 our transmission systems. SPP bills customers of ITC Great Plains on a monthly basis and collects fees for the use of ITC Great Plains’ assets. 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.
16.    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. As discussed in Note 5, during the second quarter of 2016, ITC Interconnection became a transmission owner in the FERC-approved RTO, PJM Interconnection. As a result, the newly regulated transmission business at ITC Interconnection is included in the Regulated Operating Subsidiaries segment as of June 1, 2016.
Regulated Operating Subsidiaries
We aggregate ITCTransmission, METC, ITC Midwest, ITC Great Plains and ITC Interconnection into one reportable operating segment based on their similar regulatory environment and economic characteristics, among other factors. They are engaged in the transmission of electricity within the United States, earn revenues from the same types of customers and are regulated by the FERC.
ITC Holdings and Other
Information below for ITC Holdings and Other consists of a holding company whose activities include debt financings and general corporate activities and all of ITC Holdings’ other subsidiaries, excluding the Regulated Operating Subsidiaries, which are focused primarily on business development activities.


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Regulated
 
 
 
 
 
 
 
Operating
 
ITC Holdings
 
Reconciliations/
 
 
2016
Subsidiaries (a)
 
and Other
 
Eliminations
 
Total
(In millions)
 
 
 
 
 
 
 
Operating revenues
$
1,140

 
$
1

 
$
(16
)
 
$
1,125

Depreciation and amortization
157

 
1

 
—

 
158

Interest expense — net
99

 
112

 
—

 
211

Income (loss) before income taxes
597

 
(254
)
 
—

 
343

Income tax provision (benefit)
227

 
(130
)
 
—

 
97

Net income
371

 
246

 
(371
)
 
246

Property, plant and equipment — net
6,687

 
11

 
—

 
6,698

Goodwill
950

 
—

 
—

 
950

Total assets (b)
8,162

 
4,503

 
(4,442
)
 
8,223

Capital expenditures
758

 
—

 
(8
)
 
750

 
Regulated
 
 
 
 
 
 
 
Operating
 
ITC Holdings
 
Reconciliations/
 
 
2015
Subsidiaries
 
and Other
 
Eliminations
 
Total
(In millions)
 
 
 
 
 
 
 
Operating revenues
$
1,044

 
$
1

 
$
—

 
$
1,045

Depreciation and amortization
144

 
1

 
—

 
145

Interest expense — net
97

 
107

 
—

 
204

Income (loss) before income taxes
530

 
(146
)
 
—

 
384

Income tax provision (benefit)
201

 
(59
)
 
—

 
142

Net income
329

 
242

 
(329
)
 
242

Property, plant and equipment — net
6,094

 
16

 
—

 
6,110

Goodwill
950

 
—

 
—

 
950

Total assets (b) (c)
7,463

 
4,148

 
(4,056
)
 
7,555

Capital expenditures
705

 
3

 
(7
)
 
701

 
Regulated
 
 
 
 
 
 
 
Operating
 
ITC Holdings
 
Reconciliations/
 
 
2014
Subsidiaries
 
and Other
 
Eliminations
 
Total
(In millions)
 
 
 
 
 
 
 
Operating revenues
$
1,023

 
$
1

 
$
(1
)
 
$
1,023

Depreciation and amortization
127

 
1

 
—

 
128

Interest expense — net
81

 
106

 
—

 
187

Income (loss) before income taxes
549

 
(155
)
 
—

 
394

Income tax provision (benefit)
211

 
(61
)
 
—

 
150

Net income
338

 
244

 
(338
)
 
244

Property, plant and equipment — net
5,483

 
14

 
—

 
5,497

Goodwill
950

 
—

 
—

 
950

Total assets (b) (c) (d)
6,839

 
3,932

 
(3,839
)
 
6,932

Capital expenditures
757

 
1

 
(5
)
 
753

____________________________
(a)
Amounts include the results of operations and capital expenditures from ITC Interconnection for the period June 1, 2016 through December 31, 2016.
(b)
Reconciliation of total assets results primarily from differences in the netting of deferred tax assets and liabilities at our Regulated Operating Subsidiaries as compared to the classification in our consolidated statements of financial position.


92

(c)
All amounts presented reflect the change in authoritative guidance on the presentation of debt issuance costs on the balance sheet. This change was adopted retrospectively by us in 2016. Refer to Notes 3 for more information.
(d)
All amounts presented reflect the change in the authoritative guidance issued by FASB to net all deferred income tax assets and liabilities and present as a single line item within non-current assets or liabilities on the balance sheet. This change was adopted retrospectively by us in 2015.
17.    SUPPLEMENTARY QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
 
First
 
Second
 
Third
 
Fourth
 
 
(In millions)
Quarter
 
Quarter
 
Quarter
 
Quarter
 
Year
2016
 
 
 
 
 
 
 
 
 
Operating revenues (a)
$
280

 
$
298

 
$
253

 
$
294

 
$
1,125

Operating income (a)
148

 
160

 
125

 
89

 
522

Net income (a)
64

 
71

 
50

 
61

 
246

2015
 
 
 
 
 
 
 
 
 
Operating revenues (a)(b)
$
273

 
$
275

 
$
273

 
$
224

 
$
1,045

Operating income (a)(b)
150

 
158

 
150

 
103

 
561

Net income (a)(b)
67

 
72

 
66

 
37

 
242

____________________________
(a)
During the years ended December 31, 2016 and 2015, we recognized an aggregate estimated regulatory liability for the refund and potential refunds relating to the ROE complaints as described in Note 15, which resulted in a reduction in operating revenues and operating income of $80 million and $115 million and an estimated $55 million and $73 million reduction to net income for the years ended December 31, 2016 and 2015, respectively.
(b)
During the third and fourth quarters of 2015, we recognized an aggregate regulatory liability for the refund relating to the formula rate template modifications filing as described in Note 5, which resulted in a reduction in operating revenues and operating income of $10 million and an estimated $6 million reduction to net income for the year ended December 31, 2015.


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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. The attestation report of Deloitte & Touche LLP, our independent registered public accounting firm, on the effectiveness of our internal control over financial reporting is also 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, 2016 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. As the Company is now an indirect subsidiary of Fortis, the Bylaws have been modified to remove the provisions relating to procedures by which security holders may recommend nominees to our Board of Directors.
Pursuant to the Merger Agreement and the Shareholders Agreement, the Board must consist of the Chief Executive Officer of the Company (Ms. Blair), a representative of Eiffel, the GIC subsidiary that is a minority investor in Investment Holdings (Mr. Evenden), a minority of representatives of Fortis (Messrs. Perry and Laurito) and a majority of directors who are independent of Fortis. All directors must be independent of any “market participant in MISO and SPP and a majority of the directors must be “independent” as defined in the Shareholders Agreement. See “Item 13. Certain Relationships And Related Transactions, And Director Independence — Director Independence.”
Linda H. Blair, 47. Ms. Blair 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.


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Blair 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 four regulated operating companies 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 four regulated operating companies and acting as the business unit head and president of the ITCTransmission and METC operating companies. Ms. Blair served as Executive Vice President and Chief Business Officer of the Company from June 2007 until February 2015. In this role, Ms. Blair was responsible for managing each of our regulated operating companies and the necessary business support functions, including regulatory strategy, federal and state legislative affairs, community government affairs, human resources, and marketing and communications. Prior to this appointment, Ms. Blair served as our Senior Vice President - Business Strategy and was responsible for managing regulatory affairs, policy development, internal and external communications, community affairs and human resource functions. Ms. Blair was Vice President - Business Strategy from March 2003 until she was named Senior Vice President in February 2006. Prior to joining the Company, Ms. Blair was the Manager of Transmission Policy and Business Planning at ITCTransmission for two years when it was a subsidiary of DTE Energy and was a supervisor in the regulatory affairs department of DTE Energy’s Detroit Edison subsidiary for two years.
Robert A. Elliott, 61. 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 is currently the Vice-Chair/Chair Elect of the board of directors of AAA Mountain West Group. He also served on the board of directors of AAA Arizona Inc. from 2007 to 2016 and as Lead Director of Unisource Energy Inc. from 2010 to 2014. The Board selected Mr. Elliott to serve as a director because of his accounting experience, his familiarity with Fortis subsidiary operations and his experience serving as a leader on other boards of directors.

Albert Ernst, 68. Mr. Ernst became a director of the Company in January 2017. Mr. Ernst was also a member of the ITC Holdings Board of Directors from August 2014 through the closing of the Merger in October 2016. Mr. Ernst is a retired member of the law firm of Dykema Gossett PLLC, where he also served as director of Dykema’s Energy Industry Group. His experience with companies in the public utility, energy, transmission, telecommunications and rural electric cooperative fields spans more than three decades. With Dykema, Mr. Ernst worked with leading energy clients including our subsidiaries, International Transmission Company and Michigan Electric Transmission Company. Prior to joining Dykema in 1979, Mr. Ernst was an assistant attorney general for the State of Michigan. He also served as a consultant on utility-related matters to the U.S. Department of Defense, the Department of Energy and the General Services Administration. Mr. Ernst currently serves on the board of the Sarasota Jewish Housing Council and Foundation, the board of the Sarasota Jewish Federation and is the Chairman of the Sarasota Life and Legacy Project. The Board selected Mr. Ernst to serve as a director due to his lifelong career in the energy industry, as well as his invaluable experience with public utility and energy matters and decades of experience in the practice of law.
Rhys D. Evenden, 43. Mr. Evenden became a director of the Company in October 2016. Mr. Evenden is the Head of Infrastructure — North America, GIC Private Ltd and has served in this position since January 2014. In this role he heads the North American infrastructure team, which is responsible for acquisitions and asset management for a portfolio of power, utility, midstream and transportation assets. Prior to rejoining GIC in January 2014, Mr. Evenden was a Principal at QIC Global Infrastructure. From March 2007 until December 2011, he served as a Senior Vice President at GIC Special Investments (GICSI) in London. Mr. Evenden joined GICSI from BAA Limited, where he served as Head of Business Development for outside terminal businesses across BAA Limited’s airports. Mr. Evenden currently serves on the board of directors of Oncor Electric Delivery Company, Texas Transmission Holdings Company and Bronco Holdings LLC. He previously served on the board of Starwest Generation, Yorkshire Water and its parent Kelda Holdings and as an alternate director on the board of Thames Water. Mr. Evenden was appointed as a member of our Board of Directors by Eiffel.
James P. Laurito, 59. 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


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as the President and Chief Executive Officer of Fortis’ Central Hudson Gas & Electric Corporation subsidiary from January 2010 to November 2014. Prior to joining Central Hudson, Mr. Laurito served as the President and Chief Executive Officer of both New York State Electric and Gas Corporation and Rochester Gas and Electric Corporation, subsidiaries of Avangrid, Inc. Mr. Laurito has been Chairman of the Hudson Valley Economic Development Corporation since January 1, 2015 and currently serves on the board of Fortis’ UNS Energy Corporation subsidiary.
Barry V. Perry, 52. 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, 58. Ms. Pierce became a director of the Company in January 2017. Ms. Pierce is Senior Executive Vice President, Private Client Group & Regional Banking Director and Chair of Michigan for Huntington National Bank. Ms. Pierce joined Huntington in 2016 after its merger with FirstMerit Corporation in 2016. While at FirstMerit, Ms. Pierce served as Vice Chairman of FirstMerit Corporation and Chairman and CEO of FirstMerit Michigan, from 2013 to 2016. Prior to joining FirstMerit, Ms. Pierce served as Midwest Regional Executive, President and CEO for Charter One Bank, Michigan, a division of RBS Citizens, N.A. from 2004 to 2012. Ms. Pierce currently serves as a board member of Barton Malow Enterprises and Penske Automotive Group. 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 serves as a director due to her leadership experience and familiarity with the geographic region in which the Company operates and conducts business.

Kevin Prust, 61. 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 currently serves on the board of Mercy Medical Center, in Des Moines, Iowa. In 2015 Mr. Prust served on the board of Stock Building Supply Holdings, Inc. until the company was acquired, and from 2009 to 2013 served on the board of Stark Bank Group and First American Bank. The Board selected Mr. Prust to serve as a director because of the expansive financial and accounting experience he obtained as a chief financial officer as well as his familiarity with the geographic region in which the Company operates and conducts business. The Board has determined that Mr. Prust is an “audit committee financial expert”, as that term is defined under SEC rules.
Thomas G. Stephens, 68.  Mr. Stephens became a director of the Company in January 2017. Mr. Stephens was also a member of the Board of Directors from November 2012 through the closing of the Merger in October 2016. Mr. Stephens retired in April 2012 from General Motors Company, a designer, manufacturer and marketer of vehicles and automobile parts, after 43 years with the company. Prior to his retirement, Mr. Stephens served as Vice Chairman and Chief Technology Officer from February 2011 to April 2012, Vice Chairman, Global Product Operations from 2009 to 2011, Vice Chairman, Global Product Development in 2009, Executive Vice President, Global Powertrain and Global Quality from 2008 to 2009, Group Vice President, Global Powertrain and Global Quality from 2007 to 2008, Group Vice President, General Motors Powertrain from 2001 to 2007 and has served in a variety of other engineering and operations positions. 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 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, 68. 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


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worked for Detroit Edison 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. 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. Blair, 47. Ms. Blair’s background is described above under “Directors.”
Gretchen L. Holloway, 42. Ms. Holloway was named Vice President, Interim Chief Financial Officer and Treasurer in October 2016. Prior to this role, Ms. Holloway was Vice President and Treasurer, a position in which she served since May 2016. From November 2015 until May 2016, Ms. Holloway served as Vice President, Finance and Treasurer of the Company. In that role and her immediate past role, she was responsible for all treasury and corporate planning activities including cash management and as the Company’s liaison with the investment banking community and rating agencies. Ms. Holloway served from February 2015 to November 2015 as Vice President, Finance of the Company, where she was responsible for corporate finance activities including oversight of the budget and forecast processes and other financial analysis. Prior to that, Ms. Holloway served from June 2010 until February 2015 as Director, Special Projects & Investor Relations of the Company, where she was responsible for supporting the sourcing, evaluation and execution of mergers and acquisitions and implementing investor relations strategies and objectives. Prior to joining the Company in 2004, Ms. Holloway held various finance positions at CMS Energy for five years and before that, served as a financial consultant at Arthur Andersen for three years. Ms. Holloway currently serves as a member of the Audit Committee for the Children’s Hospital of Michigan Foundation.
Jon E. Jipping, 51. Jon E. Jipping has served as our Executive Vice President and Chief Operating Officer since June 2007. In this position, Mr. Jipping is responsible for leading the company’s four regulated operating companies as well as its grid development initiatives. Mr. Jipping is also responsible for transmission system planning, system operations, engineering, supply chain, field construction and maintenance, and information technology. Prior to this appointment, Mr. Jipping served as our Senior Vice President - Engineering and was responsible for transmission system design, project engineering and asset management. Mr. Jipping joined us as Director of Engineering in March 2003, was appointed Vice President - Engineering in 2005 and was named Senior Vice President in February 2006. Prior to joining the Company, Mr. Jipping was with DTE Energy for thirteen years. He was Manager of Business Systems & Applications in DTE Energy’s Service Center Organization, responsible for implementation and management of business applications across the distribution business unit, and held positions of increasing responsibility in DTE Energy’s Transmission Operations and Transmission Planning department. Mr. Jipping currently serves as the Chair of the Advisory Board of the Michigan Technological University College of Engineering, and as a board member of the North American Transmission Forum.
Christine Mason Soneral, 44. 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 our four regulated transmission company subsidiaries. Ms. Mason Soneral joined us in September 2007 from Dykema Gossett PLLC, a national law firm where she was a member. While in private practice at Dykema from 1998 through 2007, Ms. Mason Soneral represented clients before state and federal trial courts, appellate courts and regulatory agencies. In 2014, Ms. Mason Soneral was appointed to the board of Citizens Research Council, a privately funded, not-for-profit public affairs research organization. Ms. Mason Soneral also currently serves as a member of the State Bar of Michigan's Council of Administrative and Regulatory Law Section and as a member of the Michigan State University College of Social Science's External Advisory Board.


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Daniel J. Oginsky, 44. Mr. Oginsky has served as our Executive Vice President and Chief Administrative Officer since May 2016. In this role, he has responsibility for the company’s Regulatory, Federal Affairs, Marketing and Communications, Human Resources, Strategic Planning and Enterprise Planning Process, State Government Affairs, and Local Community and Government Affairs functions. Mr. Oginsky served as Executive Vice President, U.S. Regulated Grid Development from February 2015 to May 2016. He was responsible for leading the Company’s growth and expansion through new investments in regulated electric transmission infrastructure across the United States. Mr. Oginsky joined us as our Vice President and General Counsel in November 2004, served as Senior Vice President and General Counsel since May 2009 and was named Executive Vice President and General Counsel in May 2014. In these roles, Mr. Oginsky was responsible for the legal affairs of the Company and oversaw the legal department, which included the legal, corporate secretary, real estate, contract administration and corporate compliance functions. Mr. Oginsky also served as the Company’s Secretary from November 2004 until June 2007. Prior to joining the Company, Mr. Oginsky was an attorney in private practice for five years with various firms, where his practice focused primarily on representing ITCTransmission and other energy clients on regulatory, administrative litigation, transactional, property tax and legislative matters. Mr. Oginsky currently serves as a member of the Advisory Board of Belle Tire, Inc., President of North Manitou Light Keepers, Inc. and a member of the Board of Visitors for James Madison College at Michigan State University.
Code of Conduct and Ethics
We have adopted a Code of Conduct and Ethics that applies to all of our directors, employees and executive officers, including our chief executive officer, chief financial officer and principal accounting officer. The Code of Conduct and Ethics, as currently in effect (together with any amendments that may be adopted from time to time), is available on our website at www.itc-holdings.com. To the extent required by the Code 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.
SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE

Prior to the closing of the Merger and deregistration of our common stock, Section 16(a) of the Exchange Act required our directors, executive officers and ten percent owners to file reports of holdings and transactions in our stock with the SEC. Based solely upon a review of Forms 3, 4 and 5 and amendments thereto and written representations furnished to us, our officers, directors and ten percent owners timely filed all required reports since the beginning of 2016 pursuant to Section 16(a) of the Exchange Act.
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, our Chief Financial Officer, the three other most highly compensated executive officers who were serving as such at December 31, 2016, our former President and Chief Executive Officer and our former Chief Financial Officer. We refer to these individuals collectively as the named executive officers or NEOs.

The Company’s named executive officers for 2016 were:
Name
Position
Linda H. Blair
President and Chief Executive Officer
Gretchen L. Holloway
Vice President, Interim Chief Financial Officer and Treasurer
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
Joseph L. Welch
Former President and Chief Executive Officer
Rejji P. Hayes
Former Senior Vice President and Chief Financial Officer


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Messrs. Welch and Hayes, who left the Company as employees in November 2016, are included as NEOs in the discussion below in accordance with applicable SEC rules because Mr. Hayes served as our Chief Financial Officer and Mr. Welch served as our President and Chief Executive Officer during a portion of fiscal 2016.
With respect to actions taken before October 14, 2016, “Committee” refers to the Compensation Committee as then constituted and, with respect to actions taken on or after October 14, 2016, “Committee” refers to the Governance and Human Resources Committee as reconstituted following the Merger.
Merger Agreement and the Merger
On February 9, 2016, we entered into a Merger Agreement with Fortis and certain of its subsidiaries under which ITC Holdings would become an indirect majority owned subsidiary of Fortis and our outstanding shares of common stock would be converted into (i) $22.57 in cash and (ii) .7520 shares of Fortis common stock. Under the Merger Agreement, outstanding options to acquire our common stock vested immediately prior to closing and were converted into the right to receive the difference between the Merger consideration and the exercise price of each option in cash, restricted stock vested immediately prior to closing and was converted into the right to receive the Merger consideration in cash and performance shares (including related dividend equivalents) vested immediately prior to closing at the higher of target or actual performance through the effective time of the Merger and were converted into the right to receive the Merger consideration in cash. The per share amount of Merger consideration determined in accordance with the Merger Agreement and used for purposes of settling the share-based awards was $45.72.
On October 14, 2016, we closed the Merger. The discussion below focuses on the compensation of ITC Holdings and does not reflect the compensation programs of Fortis, which did not affect the compensation of the NEOs in 2016.
Executive Summary
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 bonus, long-term incentives, as well as certain perquisites and other benefits. In determining the amount of NEO compensation, we consider competitive compensation practices by our peer companies, 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 2016:
•
Base salary increases. As a result of our annual review process and in light of the Merger Agreement, our NEOs serving as such at the time did not receive a regular base salary increase in 2016. However, Ms. Blair received a promotional base salary increase in connection with her appointment to President and Chief Executive Officer and Ms. Holloway received a regular base salary increase early in the year prior to becoming the interim Chief Financial Officer in November, based on market data and performance and other factors.

•
Annual cash incentive bonuses. Except with respect to Mr. Welch, our former Chief Executive Officer, we paid annual corporate performance bonuses for 2016 in two parts as a result of the closing of the Merger. Upon closing and in accordance with the Merger Agreement, a prorated portion of the annual bonus through the closing of the Merger was paid out at 200% of the “target bonus levels” to our NEOs except for Ms. Mason Soneral and Mr. Hayes, who each reached an agreement with the Company for part of their 2016 annual bonus to be paid in the ordinary course in accordance with their respective employment agreement and the Company’s past practices based on actual 2016 performance. The prorated balance, representing the period after the Merger through the end of the year, was paid out based on actual performance. Mr. Welch’s annual corporate performance bonus and an additional cash bonus of $250,000 that he was awarded in May 2016 were paid in full in connection with his retirement from the Company and the October 2016 letter agreement amending his employment agreement. See


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“Compensation Discussion and Analysis — Key Components of Our NEO Compensation Program — Bonus Compensation” and “Welch Letter Agreement”.

•
Milestone bonuses. We made a final project-related bonus payment in January 2016 related to the successful completion of the Kansas V-Plan transmission project. This project was critical to our ability to provide reliable service to our customers and deliver value to our shareholders.

•
Long-term equity incentives. We granted long-term equity incentive awards to our NEOs in May 2016. Total award values were determined as a percentage of base salary and delivered 100% in the form of restricted stock. While options and performance-based shares had been awarded in recent years, the Committee granted only restricted stock in 2016 in accordance with the Merger Agreement.

•
Retention bonuses. In accordance with the Merger Agreement, we entered into retention award agreements with certain NEOs. 30% of these awards were paid upon closing of the Merger with the remaining 70% payable on the first anniversary of closing provided the NEO remains employed with the Company.
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 incentivizing excessive risk taking.
In early 2016, the Committee engaged Pay Governance, its independent compensation consultant, to conduct a comprehensive compensation program risk assessment. Pay Governance reviewed the attributes and structure of our executive compensation programs for the purpose of identifying potential sources of risk within the program design. The review covered plan design and administration/governance risk, corporate governance and investor relations risk and talent risk.


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Based on a report from Pay Governance 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 and long-term incentive plans, caps on annual bonus and equity payouts, various performance measures that are both financially and operationally focused, a compensation recoupment policy, share ownership guidelines, regular review of share utilization (overhang, dilution and run rates), 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. Effective for 2016, we changed our market definition for pay benchmarking. Instead of attempting to define a peer group, we utilized two distinct market samples, as reflected in published surveys to develop competitive market rates. Pay Governance compiled data for the following components of compensation — base salary, target annual incentive and target long-term incentive, as well as target total cash compensation and target total direct compensation. The references reflected 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 industry data due to the industry-specific nature of the roles. The market data were aged and size-adjusted using regression analyses to correspond to our adjusted revenue scope. We then applied an adjustment to our revenues to account for our unique business model and to reflect the competitive incremental revenue that would normally be imbedded in rates to reflect a typical cost of goods sold factor.
Our compensation strategy is to target compensation to be in the range between the median and 75th percentile of the market data, based on consideration of individual characteristics (performance, experience, etc.), internal equity and other factors. In February 2016, the Committee, through Pay Governance, conducted a benchmarking study comparing NEO target total direct compensation, which is the sum of base salary, target annual corporate performance awards and target long-term incentives, to the 50th, 65th and 75th percentile survey data to assess the market competitiveness of our compensation opportunities. Target total direct compensation provided to our NEOs is within the targeted range when compared to the average of the two market survey data samples. This is generally achieved by having base salaries at the lower end of the targeted market range with higher target incentive opportunities that combine to provide competitive target total direct compensation.
Use of Tally Sheets. The Committee reviews tally sheets as prepared by management and the Committee’s independent advisor, to facilitate its assessment of the total annual compensation of our NEOs. The tally sheets contained annual cash compensation (salary and bonuses), long-term equity incentives, benefit contributions and perquisites. In addition, the tally sheets included 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 and review of tally sheets, our Chief Executive Officer reviewed and examined market survey compensation levels and practices, as well as individual responsibilities and performance, our compensation philosophy and other related information to determine the appropriate level of compensation for each of our NEOs. The Chief Executive Officer evaluated the performance of the other NEOs and made recommendations on their salaries, target bonus levels and long-term incentive awards. The Committee considered these recommendations in its decision making and conferred with its compensation consultant to understand the impact and result of any such recommendations. The Committee used market data and recommendations from its consultant and made recommendations for the Chief Executive Officer’s salary, target bonus level and long-term incentive awards to the Board of Directors. The Board of Directors (other than the Chief Executive Officer) evaluated the Chief Executive Officer’s performance and considered the Committee’s recommendations in its decision making.
The Committee reviewed and considered each element of compensation and all elements of compensation together in measuring total compensation packages as part of its benchmarking analyses and in measuring compensation packages against the objectives of our compensation program. 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


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were also considered in the context of 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.
•
Bonus Compensation — encourages and rewards contributions to our corporate performance goals.
•
Long Term Incentives — encourages equity ownership, 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) of our NEOs was generally above the 75th percentile of the utility industry, but is within the targeted range when compared to the general industry and average of the two 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 within 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 Chief Executive Officer and the target total direct compensation package as well as the benchmarking analysis conducted by its advisor.
The 2016 base salaries for the NEOs, including any year-over-year change, were:
NEO
 
2016 Base Salary
 
Percent Increase
Linda H. Blair
 
$
725,000

 
18.1
%
Gretchen L. Holloway
 
215,000

 
7.5
%
Jon E. Jipping
 
502,000

 
—
%
Daniel J. Oginsky
 
423,000

 
—
%
Christine Mason Soneral
 
350,000

 
—
%
Joseph L. Welch
 
1,023,400

 
—
%
Rejji P. Hayes
 
$
400,000

 
—
%
In May 2016, before becoming an executive officer, Ms. Holloway received an increase in her base salary from $200,000 to $215,000 based on market review and performance. Due to restrictions in the Merger Agreement, the base salaries of the other NEOs were held constant.
In October 2016, in connection with her appointment to President and Chief Executive Officer, the Board of Directors approved an increase to Ms. Blair’s salary from $614,000 to $725,000. The increase was based on various factors, including market data, internal equity and in consultation with Fortis.


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Bonus Compensation
Annual bonus awards based on corporate performance goals, as well as occasional cash bonuses made on a discretionary basis upon completion of significant projects or milestones, have been used to provide incentives for and to reward contributions to our growth and success. Annual corporate performance bonuses for 2016 are listed in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table in this Item 11. Project-related bonuses for 2016 are listed in the Bonus column of the Summary Compensation Table.
Annual Corporate Performance Bonus. Early each year, the Committee has approved our annual corporate performance bonus plan goals and targets, which are based on key Company objectives relating to operational excellence and superior financial performance. The corporate performance goals and targets were designed to align the interests of customers, shareholders and management, and encourage teamwork and coordination among all of our executives and employees with a common focus on the growth and success of the Company. Target levels for the corporate performance goals were determined based on long-term strategic plans, historical performance, expectations for future growth and desired improvement over time.
The annual bonus plan performance goals were individually weighted. Weights were assigned to each goal based on areas of focus during the year and difficulty in achieving target performance. Weights were also assigned so that there was a balance between operational and financial goals. Each goal operated independently, and, for most goals, there was not a range of acceptable performance; if a goal was not achieved, there was no payout for that goal. The plan would not pay for achieving below-target performance on any goal, but would pay for achievement of target performance on those goals that were achieved even though other goals were not achieved. Where performance goals were stated in a range, the threshold goals were generally expected to be achieved while the maximum goals were considered “stretch” goals with lower expectation of achievement. The bonus goal targets were established to motivate NEOs toward operational excellence and superior financial performance and were designed to be challenging to meet, while remaining achievable.
For 2016, financial measures drove 60% of the target bonus opportunity, while operational performance measures drove the remaining 40% 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 that were used in connection with these goals established 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 2016, 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 60% of the total annual bonus target and included specific measures for Non-Field Operation and Maintenance Expense, Net Income and TSR, with a maximum potential payout opportunity of 120% of the target bonus level.
Category
 
Goal
 
Rationale for Goal
 
Rationale for Target Goal
 
Potential Payout
 
2016 Results
 
Actual Payout
Financial

60% Weight / 120% Maximum Potential Payout
 
Non-field Operation and Maintenance Expense
 
Controlling general and administrative expenses is an important part of controlling rates charged to transmission customers.
 
Target is consistent with the approach used in 2015 and reflects the 2016 Board-approved budget.

Non-Field O&M and G&A expense at or under budget of $161 million.
 
10
%
 
$149.0 million
 
10%
 
Net Income (1)
 
Represents the Company’s financial performance as it reflects a true measure of earnings contributions from the operating companies.
 
Target reflects the 2016 Board-approved budget.

Net Income at or above $393 million to achieve 10%;
Net Income at or above $373 million to achieve 5%.
 
5% - 10%

 
$405.2 million
 
10%
 
Total Shareholder Return (TSR) (2)
 
Represents the Company’s TSR relative to the TSR of each of the companies that comprise the Dow Jones Utilities (DJU) Average Index.
 
Target is based on percentile rank relative to companies in the DJU Average Index and must be positive. See chart below.
 
20%-100%

 
87.5%
 
80%
Total
 
120
%
 
 
 
100%


104

Safety & Compliance goals represented 10% of the total annual bonus target and included specific measures for Lost Time, Recordable Incidents and Infrastructure Protection, with a maximum potential payout opportunity of 20% of target bonus level:
Category
 
Goal
 
Rationale for Goal
 
Rationale for Target
 
Potential Payout
 
2016 Results
 
Actual Payout
Safety & Compliance

10% Weight / 20% Maximum Potential Payout
 
Safety as measured by lost time
 
Maintaining the safety of our employees and contractors is a core value and is at the foundation of our success.
 
Target number of incidents remained the same as prior years and was based on industry top decile performance, which reflects an aggressive view and philosophy on the importance of safety.

2 or fewer lost work day cases
 
5
%
 
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
 
5
%
 
5
 
5%
 
Infrastructure Protection
 
Maintaining cyber and physical security is critical to ensuring system reliability and ongoing operations.
 
Goal focused on implementing updated cyber-security and physical security plans. Emphasized securing our information systems and our most important assets.

Implementation of the 2016 portion of the Cyber Security and CIP (critical infrastructure protection) Plan and the Physical Security Plan, as presented to and approved by the Board of Directors, each plan worth 5%.
 
10
%
 
Completed
 
10%
Total
 
20
%
 
 
 
20%


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System Performance goals represented 30% of the total annual bonus target and included specific measures for System Outages, Maintenance Plans and System Development, with a maximum potential payout opportunity of 60% of target bonus level:
Category
 
Goal
 
Rationale for Goal
 
Rationale for Target
 
Potential Payout
 
2016 Results
 
Actual Payout
System Performance

30% Weight / 60% Maximum Potential Payout
 
Outage frequency
 
Reducing and limiting system outages are critical to ensuring system reliability.
 
Target unchanged from prior year. Number of Forced, Sustained Line Outages, excluding the "External" cause classification, for:

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

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

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

Each target worth 5%.
 
20
%
 
ITCTransmission - 11

METC - 15

ITC Midwest - 59/ 41

ITC Midwest - 65.6%
 
20%
 

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 2016 Field O&M Initiatives for:

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

Each subsidiary target worth 5%.
 
15
%
 
All high priority initiatives completed
 
15%
 
Capital Project Plan
 
Performing necessary system upgrades is critical to ensuring system reliability, providing a robust transmission grid and delivering financial performance.
 
Target continues to tie to external guidance on the current year capital project plan.

The maximum payout represents the midpoint of our 2016 capital investment guidance range, with a threshold level also established.
 
15 - 25%

 
Midpoint of guidance achieved
 
25%
 
 
60
%
 
 
 
60%
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Bonus (as a percent of target bonus level)
 
200
%
 
 
 
180%
____________________________
(1)
Net Income was risk-adjusted. Targets were adjusted for any potential impacts associated with changes to the MISO ROE refund estimate (and associated interest expense) assumed in the budget, amounts recognized for actual or probable rate refunds (including interest expense) as a result of Section 205 or 206


106

proceedings at FERC (including the retroactive and prospective effects of any items requiring refunds when not included in establishing the targets), the impact associated with asset impairments and gain/losses associated with debt extinguishment. The targets also assumed that bonus depreciation was not used by the Company. Because the Company was required to elect bonus depreciation, actual amounts were adjusted to eliminate the effect of bonus depreciation for all relevant periods for purposes of measuring achievement of the goal.
(2)
Total Shareholder Return was compared to the Dow Jones Utility Average Index companies. Total Shareholder Return must be positive for the year and must exceed the 50th percentile of the Dow Jones Utility Average Companies before there would be any payout for meeting this goal, as illustrated below:
Total Shareholder Return relative to each of the Dow Jones Utility Average Companies
 
Payout % of Salary
1st to 50th percentile
 
—
%
51st to 60th percentile
 
20
%
61st to 70th percentile
 
40
%
71st to 80th percentile
 
60
%
81st to 90th percentile
 
80
%
91st to 100th percentile
 
100
%
We computed Total Shareholder Return as follows:
A:  Calculated the average of the closing prices from October 5, 2015 to December 31, 2015
B: Calculated the average of the closing prices from July 15, 2016 to October 12, 2016
C: Calculated total dividend paid per share in 2016
Total Return to Shareholders:  (B — A + C)/A
Bonuses were based on a percentage of his or her base salary. The Committee considers each individual’s job responsibilities and the results of its benchmarking analysis when determining the base bonus percentage for the executive officers, including the NEOs, which we refer to as the “target bonus levels”. Target bonus levels for 2016 were as follows:

NEO
% of Base Salary
Linda H. Blair
100
%
Gretchen Holloway
40
%
Jon E. Jipping
100
%
Daniel J. Oginsky
100
%
Christine Mason Soneral
100
%
Joseph L. Welch
125
%
Rejji P. Hayes
100
%
Ms. Blair’s total target cash compensation, in her new role as President and CEO, is near the utility industry median. Total target cash compensation for the other NEOs is within the target range of the market 50th and 75th percentile, purposely weighted more towards performance-based compensation, which is consistent with our compensation philosophy. Ms. Holloway’s target bonus level reflects her target incentive for her role as Vice President, Finance and Treasurer.
Upon closing of the Merger and in accordance with the Merger Agreement, a prorated portion of the annual bonus through the closing of the Merger was paid out at 200% of the target bonus levels to our NEOs except for Ms. Mason Soneral and Mr. Hayes, who each reached an agreement with the Company for part of their 2016 annual bonus to be paid in the ordinary course in accordance with their respective employment agreement and the Company’s past practices based on actual 2016 performance. The prorated portion of the annual bonus for the period after the Merger through the end of the year and the portion of Ms. Mason Soneral’s bonus agreed to be paid after year end were paid out based on actual performance as set forth in the tables above. Mr. Welch’s annual corporate performance bonus and an additional cash bonus of $250,000 that he was awarded in May 2016 were paid in full in connection


107

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

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

Project Bonuses.    In January 2016, the Committee approved the final payment of cash bonuses to all executives, including NEOs, in connection with the Kansas V-Plan project being placed into service. The final Kansas V-Plan project bonus was paid in February 2016.
2012 Retention Compensation Agreement. Pursuant to a retention compensation arrangement for Mr. Welch entered into in 2012, he was entitled to be paid cash payments of $1,500,000 on each of June 30, 2014 and June 30, 2016, if he satisfied continued employment and satisfactory performance conditions as the Company’s Chief Executive Officer as of such dates. The payments under the agreement were not included in the calculation of retirement benefits payable to Mr. Welch pursuant to the MSBP. The Committee determined that Mr. Welch met the “satisfactory performance” standard for purposes of each of the payments.
Long-Term Incentives
Through the closing of the Merger, the Committee provided and maintained a long-term incentive program under the ITC Holdings Corp. 2015 Long Term Incentive Plan, or 2015 LTIP. With the closing of the Merger, all outstanding awards under the 2015 LTIP and its terminated predecessor plan, the 2006 LTIP, became vested and converted into the right to receive cash, per the Merger Agreement, and the 2015 LTIP was then terminated.
In May 2016, the Committee approved grants of restricted stock to employees, including the NEOs, under the 2015 LTIP based on our CEO’s recommendation, and also on the Committee’s assessment of the performance of the Company and the executive. Awards to the Chief Executive Officer were also presented to the Board of Directors by the Committee and ratified by the Board of Directors. The amounts and terms of the 2016 restricted stock grants made under the 2015 LTIP are described in the narrative following the Grants of Plan-Based Awards Table.
The awards were designed to reward, motivate and encourage performance, act as a retention mechanism, and further align the interests of the NEOs with the interests of shareholders. As in past years, total value for the award for each grantee was determined based on a percentage of salary. For the NEOs, when the May 2016 awards were made, the award values were targeted to be:
NEO
Grant Value Percent of Salary
Ms. Blair
175
%
Ms. Holloway
65
%
Mr. Jipping
175
%
Ms. Mason Soneral
175
%
Mr. Oginsky
175
%
Mr. Welch
260
%
Mr. Hayes
175
%
Ms. Holloway’s long-term incentive opportunity represents the target for her role as Vice President, Finance and Treasurer. In October 2016, the Board, with the recommendation of the Committee, effective for 2017, increased Ms. Blair’s targeted award from 175% to 250% of annual base compensation in connection with her appointment to President and Chief Executive Officer, based on market data and in consultation with Fortis. This element of target compensation is very volatile and can produce significant variances in year-over-year levels, as well as in the actual value realized, if any, upon completion of the multi-year performance/vesting periods. In determining the size of grants under the long term incentive program and the award mix, the Committee considered market practice, the recommendation of the Chief Executive Officer (with respect to grants other than to the Chief Executive Officer) in light of comparisons to benchmarking data, expense to the Company and dilution of shareholder value, as well as


108

amounts that it believes will motivate performance to achieve continued growth in shareholder value. While options and performance-based shares had been awarded in recent years, the Committee granted only restricted stock in 2016 in accordance with restrictions in the Merger Agreement. The Board expects to adopt a plan allowing cash based awards or grants of Fortis stock-based units that settle only in cash beginning in 2017.
Other Components of Our Executive Compensation Program
Pension Benefits. As is common in our industry and as established pursuant to our initial formation requirements included in the acquisition agreement with DTE Energy for ITCTransmission, we maintain a tax-qualified defined benefit retirement plan for eligible employees, comprised of a traditional pension component and a cash balance component. All employees, including the NEOs, participate in either the traditional component or the cash balance component. We have also established two supplemental nonqualified, noncontributory retirement benefit plans for selected management employees: the Management Supplemental Benefit Plan, or MSBP, in which only Mr. Welch participates and the Executive Supplemental Retirement Plan, or ESRP, in which all other NEOs participate. These plans provide for benefits that supplement those provided by our qualified defined benefit retirement plan. Benefits payable to the NEOs pursuant to the retirement plans are set by the terms of that plan. The Committee exercises no regular discretionary authority in the determination of benefits. The retirement plans may be modified, amended or terminated at any time, although no such action may reduce a NEO’s earned benefits and, with regard to the MSBP, changes must generally be agreed to by Mr. Welch. Mr. Welch retired in November 2016. See “Pension Benefits” for information regarding participation by the NEOs in our retirement plans as well as a description of the terms of the plans.
For Mr. Welch, the Change in Pension Value & Non-Qualified Deferred Compensation Earnings column of the Summary Compensation Table includes amounts associated with the MSBP. Mr. Welch retired under DTE Energy’s Management Supplemental Benefit Plan, though with lower benefits than he would have earned with additional service. In order to compensate Mr. Welch for the value of benefits he would have received had he remained with DTE Energy, the Company agreed to establish the MSBP such that his retirement benefits would be calculated to include service with DTE Energy, with the resulting amount offset by the benefits he is receiving from DTE Energy. The MSBP is described in detail in “Pension Benefits — Management Supplemental Benefit Plan” following the Pension Benefits Table.
Benefits and Perquisites. The NEOs participate in a variety of benefit programs, which are designed to enable us to attract and retain our workforce in a competitive marketplace. These programs include our Savings and Investment Plan, which consists of an employee deferral contribution component and an employer safe-harbor matching contribution component.
Our NEOs are provided a limited number of perquisites in addition to benefits provided to our other employees. The purpose of these perquisites is to minimize distractions from the NEOs’ attention to important Company initiatives, to facilitate their access to work functions and personnel, and to encourage interactions among NEOs and others within professional, business and local communities. NEOs are provided perquisites such as auto allowance, financial, estate and legal planning, income tax return preparation, annual physical, club memberships, and personal liability insurance. Additionally, we own aircraft to facilitate the business travel schedules of our executives and other employees, particularly to locations that do not provide efficient commercial flight schedules. While serving as President and CEO, Mr. Welch and guests who traveled with him were permitted to travel for personal business on our aircraft, with an annual maximum of 125 flight hours for such personal travel.
We purchase tickets to various sporting, civic, cultural, charity and entertainment events. We use these tickets for business development, partnership building, charitable donations and community involvement. If not used for business purposes, we may make these tickets available to employees, including the NEOs, as a form of recognition and reward for their efforts. Because such tickets have already been purchased, we do not believe that there is any aggregate incremental cost to the Company, if a NEO uses a ticket for personal purposes.

Except for Mr. Welch prior to his retirement in November 2016, none of the NEOs are reimbursed for income taxes associated with the value of the perquisites. Our employment agreements provide for limited tax gross-ups following termination in some circumstances. The Committee continues to monitor and review the Company’s perquisite program. Perquisites are further discussed in footnote 6 to the Summary Compensation Table.

Potential Severance Compensation. Pursuant to their employment agreements, each NEO is entitled to certain benefits and payments upon a termination of his or her employment. Benefits and payments to be provided


109

vary based on the circumstances of the termination. We believe it is important to provide these protections in order to ensure our NEOs will remain engaged and committed to us during an acquisition of the Company or other transition in management. See “Employment Agreements and Potential Payments Upon Termination or Change in Control” for further detail on these employment agreements, including a discussion of the compensation to be provided upon termination or a change in control and the changes made to the prior agreements.
In addition to severance benefits identified in their employment agreements, pursuant to the Merger Agreement, all share-based awards vested immediately prior to closing and were converted into the right to receive cash equal to the value of the Merger consideration.
Recoupment Policy
Our Recoupment Policy provides that in the event of any restatement of financial results, the officer will be required to reimburse the Company for an amount equal to the sum of:
•
Any bonus or other incentive-based or equity-based compensation received, earned or recognized by the officer from the Company during the 12-month period following the first public issuance or filing with the SEC of the financial document embodying such financial reporting requirement in excess of the amount that would have been received, earned or recognized if the restated financial results had been released instead; and
•
Any profits realized by the officer from the sale of securities of the Company during that 12-month period.
The Board of Directors or the Committee will determine, in its reasonable discretion, based on the circumstances, the amount, form and timing of recovery. The Recoupment Policy applies to the equity based grants made after the effective date of the policy and to incentive cash compensation awards made for fiscal years beginning with 2014.
Welch Letter Agreements
In connection with the Merger Agreement, the Company entered into a letter agreement with Mr. Welch, dated February 8, 2016, that amended the terms of his employment agreement. Under the terms of the February 8 letter agreement, Mr. Welch’s employment would have become “at-will”, effective as of December 21, 2016. Following that date, if Mr. Welch’s employment had been terminated for any reason, including his retirement, Mr. Welch would not have been entitled to any severance payments or benefits under his employment agreement other than his accrued rights (as defined under his employment agreement), and he would no longer have been subject to the post-termination covenants set forth in his employment agreement restricting competition and solicitation of our customers and employees. Additionally, after December 21, 2016, either Mr. Welch or the Company would have been entitled to select Mr. Welch’s retirement date at any time and for any reason.
Under the February 8 letter agreement, if Mr. Welch’s employment were terminated after December 21, 2016, due to his retirement (other than due to a retirement date selected by us in connection with a cause event), death or disability, (A) all of his unvested stock options and restricted stock grants would have fully vested upon termination and (B) with respect to all his unvested performance shares, Mr. Welch would have received, following the vesting date under the applicable performance shares award agreement, the number of shares to which Mr. Welch would have otherwise been entitled if he had remained employed through such vesting date. If Mr. Welch had remained employed at the time cash and equity incentive awards were granted in the ordinary course, the February 8 letter agreement provided that he would have been entitled to receive cash and equity incentive awards that were consistent with his employment agreement and commensurate with his role as our Chief Executive Officer.
On October 14, 2016, Mr. Welch notified the Company that he would resign as the Company’s President and Chief Executive Officer, effective November 1, 2016. In exchange for providing transition services to the Company, Mr. Welch entered into a letter agreement dated October 14, 2016 that superseded Mr. Welch’s previous agreement with the Company, dated December 21, 2012, as amended by the February 8 letter agreement. Pursuant to the October 14 letter agreement, Mr. Welch received a lump sum payment of $1,300,000 in exchange for, among other items, transition services, waiving his potential right to receive certain post-retirement severance payments under the employment agreement and a general release of any claims against the Company. Mr. Welch also received all compensation accrued to him prior to his retirement, including his entire annual corporate performance bonus based


110

on target performance through the closing of the Merger and the $250,000 discretionary cash bonus awarded in May 2016.
Retention Program
In May 2016, as contemplated by the Merger Agreement, we adopted a retention program for the retention of key talent for the period commencing on the date of the Merger Agreement through the one-year anniversary of the effective time of the Merger, pursuant to which our executive officers (other than Mr. Welch) were granted the opportunity to earn a retention bonus. Under the terms of the retention award letters, recipients received 30% of the retention award as long as they were employed by the Company on the effective date, and will receive the remaining 70% if they remain employed by the Company through the first anniversary of the effective date (and payments may be accelerated upon the recipient’s qualifying termination, which includes any termination for which severance would be payable). The amount of each named executive officer’s potential retention bonus amount is listed below:
NEO
 
Retention Award
Linda Blair
 
$
921,000

Gretchen Holloway
 
200,000

Jon Jipping
 
753,000

Daniel Oginsky
 
634,500

Christine Mason Soneral
 
525,000

Joseph Welch
 
—

Rejji Hayes
 
$
600,000

Mr. Hayes and Ms. Mason Soneral’s agreements provided for them to receive an additional award in the amount of $300,000 each if the Merger closed on or before December 31, 2016 and they remained employed by the Company on the effective date of the Merger. Both conditions were met for each of these NEOs.
Employment Agreement Amendments — Mason Soneral and Hayes
In October 2016, to address cutback language in their employment agreements that could have caused them to be treated differently than other NEOs, the employment agreements with Ms. Mason Soneral and Mr. Hayes were amended to (1) have their annual bonus (with the exception of the total shareholder return component which was paid out pursuant to the terms of the Merger Agreement) payable in the ordinary course in accordance with their respective employment agreement and the Company’s past practices based on actual 2016 performance; (2) have a portion of their Company performance shares canceled and (3) provide for payment of additional cash compensation in a comparable amount over five installments following the Merger, contingent on continued employment with the Company on each installment date. Ms. Mason Soneral will receive total retention payments of $162,399 payable in five equal installments to be paid on the first payroll date following the first day of each fiscal quarter beginning January 1, 2017, contingent on her continued service to the Company or its affiliates on each applicable payment date. Because Mr. Hayes resigned from his position with the Company as of November 25, 2016, the Company was not required to pay the annual bonus in February 2017 and will not be required to make the cash installment payments.
Governance and Human Resources Committee Report
The Governance and Human Resources Committee has reviewed and discussed this Compensation Discussion and Analysis with management and, based on the review and discussions with management, has recommended to the Board of Directors that the Compensation Discussion and Analysis be included in this report.
RHYS D. EVENDEN    BARRY V. PERRY    SANDRA E. PIERCE    THOMAS G. STEPHENS
Summary Compensation
The following table provides a summary of compensation paid or accrued by the Company and its subsidiaries to or on behalf of the NEOs for services rendered by them during each of the last three calendar years, as required


111

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 ($)(1)
 
Bonus
($) (2)
 
Stock Awards ($) (3)
 
Option Awards
($) (3)
 
Non-Equity Incentive Plan Compensation ($) (4)
 
Change in Pension Value & Non-qualified Deferred Compensation Earnings ($)(5)
 
All Other Compensation ($) (6)
 
Total ($)
(a)
 
(b)
 
(c)
 
(d)
 
(e)
 
(f)
 
(g)
 
(h)
 
(i)
 
(j)
Linda H. Blair,
President & CEO (7)
 
2016
 
$
635,146

 
$
659,662

 
$
1,074,490

 
—

 
$
1,244,401

 
$
291,249

 
$
41,301

 
$
3,946,249

 
2015
 
616,362

 
222,164

 
744,344

 
342,146

 
598,650

 
41,875

 
37,990

 
2,603,531

 
2014
 
627,515

 
131,234

 
322,342

 
730,851

 
706,100

 
310,407

 
38,588

 
2,867,037

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gretchen L. Holloway
VP, Interim CFO & Treasurer (8)
 
2016
 
210,116

 
60,000

 
139,761

 
—

 
168,337

 
71,163

 
31,312

 
680,689

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jon E. Jipping,
EVP & COO
 
2016
 
503,931

 
539,333

 
878,517

 
—

 
982,615

 
365,553

 
37,269

 
3,307,218

 
2015
 
503,931

 
207,775

 
608,587

 
279,734

 
489,450

 
82,651

 
36,010

 
2,208,138

 
2014
 
516,623

 
137,603

 
263,358

 
597,533

 
577,300

 
455,009

 
36,279

 
2,583,705

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Daniel J. Oginsky,
EVP & CAO (9)
 
2016
 
424,627

 
454,458

 
740,250

 
—

 
827,980

 
213,915

 
35,497

 
2,696,727

 
2015
 
424,627

 
153,055

 
512,812

 
235,714

 
412,425

 
13,883

 
26,869

 
1,779,385

 
2014
 
430,012

 
86,697

 
222,070

 
503,498

 
486,450

 
234,481

 
25,970

 
1,989,178

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Christine Mason Soneral, SVP & General Counsel (10)
 
2016
 
351,346

 
524,557

 
612,487

 
—

 
695,590

 
135,364

 
35,675

 
2,355,019

 
2015
 
328,777

 
38,861

 
775,093

 
195,034

 
341,250

 
112,077

 
13,950

 
1,805,042

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Joseph L. Welch, Director and Former President & CEO (11)
 
2016
 
920,076

 
2,349,042

 
2,660,821

 
—

 
2,013,540

 
13,310,749

 
1,575,536

 
22,829,764

 
2015
 
1,027,336

 
976,180

 
1,843,228

 
847,266

 
1,247,269

 
4,787,563

 
377,529

 
11,106,371

 
2014
 
1,012,182

 
2,314,262

 
1,862,578

 
775,648

 
1,471,138

 
8,544,075

 
375,715

 
16,355,598

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Rejji P. Hayes, Former EVP & CFO (12)
 
2016
 
374,808

 
480,000

 
699,992

 
—

 
314,800

 
28,737

 
28,426

 
1,926,763

 
2015
 
395,192

 
—

 
854,951

 
222,894

 
390,000

 
68,429

 
31,927

 
1,963,393

 
2014
 
$
289,092

 
$
30,000

 
$
50,798

 
$
115,175

 
$
373,750

 
$
82,560

 
$
34,370

 
$
975,745

____________________________
(1)
The compensation amounts reported in this column include the $20,000 lump sum cash payments made to Ms. Blair, Mr. Jipping and Mr. Oginsky in 2014.
(2)
The compensation amounts reported in this column include, (a) awards under the Special Bonus Plan, (b) bonuses paid in connection with project milestones, efforts related to the proposed Entergy transaction and completion of the Merger, (c) retention bonuses and (d) a discretionary cash bonus made to Mr. Welch in 2016. Bonuses under the Special Bonus Plan, were awarded at the sole discretion of the Committee and were equal to per share dividend amounts paid by the Company multiplied by the number of options granted in 2003 and 2005. These options were exercised and the Special Bonus Plan expired in 2015. In each year, the NEOs, except for Mr. Hayes, received certain project-related bonuses in recognition of the successful completion of various transmission development milestones. In 2014, while Mr. Hayes served in his prior position as our Vice President Finance and Treasurer, he received a cash bonus in recognition of the integral role he played in the Company’s pursuit of the transmission business of Entergy Corporation. On May 19, 2016, the Committee approved a discretionary cash bonus to Mr. Welch in the amount of $250,000 which was to be paid at the same time as the payment of the 2016 annual corporate performance bonus. This amount was included in the payment made pursuant to Mr. Welch’s October 2016 letter agreement. These bonuses are set forth in the following table under Other Bonuses. Mr. Hayes and Ms. Mason Soneral received $300,000 each since the Merger was closed before December 31, 2016. In 2014 and 2016, Mr. Welch received a bonus pursuant to his Retention Compensation Agreement. In 2016, all of the NEOs (other than Mr. Welch) received 30% of their retention award due to the closing of the Merger. See “Compensation


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Discussion and Analysis — Retention Program”. The remainder of the Merger-related bonuses will become earned in 2017 but only if the NEOs remain employed by the Company on the one-year anniversary of the closing of the Merger.
Name
 
Year
 
Special Bonus ($)
 
Retention Bonus ($)
 
Merger Completion ($)
 
Other Bonuses ($)
 
Total Bonus ($)
 
 
 
 
 
 
 
 
 
 
 
 
 
Linda H. Blair
 
2016
 
$
—

 
$
276,300

 
—

 
$
383,362

 
$
659,662

 
2015
 
—

 
—

 
—

 
222,164

 
222,164

 
2014
 
22,919

 
—

 
—

 
108,315

 
131,234

Gretchen L. Holloway
 
2016
 
—

 
60,000

 
—

 
—

 
60,000

Jon E. Jipping
 
2016
 
—

 
225,900

 
—

 
313,433

 
539,333

 
2015
 
26,136

 
—

 
—

 
181,639

 
207,775

 
2014
 
49,055

 
—

 
—

 
88,548

 
137,603

Daniel J. Oginsky
 
2016
 
—

 
190,350

 
—

 
264,108

 
454,458

 
2015
 
—

 
—

 
—

 
153,055

 
153,055

 
2014
 
13,115

 
—

 
—

 
73,582

 
86,697

Christine Mason Soneral
 
2016
 
—

 
157,500

 
$
300,000

 
67,057

 
524,557

 
2015
 
—

 
—

 
—

 
38,861

 
38,861

Joseph L. Welch
 
2016
 
—

 
1,500,000

 
—

 
849,042

 
2,349,042

 
2015
 
313,627

 
—

 
—

 
662,553

 
976,180

 
2014
 
588,654

 
1,500,000

 
—

 
225,608

 
2,314,262

Rejji P. Hayes
 
2016
 
—

 
180,000

 
300,000

 
—

 
480,000

 
2015
 
—

 
—

 
—

 
—

 
—

 
2014
 
$
—

 
$
—

 
$
—

 
$
30,000

 
$
30,000

(3)
The amounts reported in these columns represent the fair value of stock option, performance share and restricted stock awards granted to the NEOs under the 2015 LTIP and the 2006 LTIP, excluding any forfeiture reserves recorded for these awards. Restricted stock awards are recorded at fair value at the date of grant, which is equivalent to the share price on that date. In accordance with Financial Accounting Standards Board Accounting Standards Codification 718, or ASC 718, the fair value of the performance share awards with the three-year relative TSR metric was determined using a Monte Carlo simulation valuation model and the fair value of the performance shares with the three-year Diluted EPS Growth metric was based on the share price on the date of grant. The grant date present value of the stock options was determined in accordance with ASC 718 using a Black-Scholes option pricing model and the following assumptions:
Year
 
Remaining Future Life of Option
 
Expected Volatility
 
Risk Free Interest Rate
 
Expected Life (Years)
 
Expected Dividend Yield
 
Share Price at Grant Date
 
2016
 
—

 
—
%
 
—
%
 
—

 
—
%
 
$
—

2015
 
9.3

 
18.6
%
 
1.81
%
 
6

 
1.59
%
 
$
35.91

2014
 
8.3

 
27.2
%
 
1.8
%
 
6

 
1.55
%
 
$
36.73

(4)
The amounts reported in this column include cash awards tied to the achievement of annual Company performance goals under our bonus plan in effect for each of 2016, 2015 and 2014. For information regarding the corporate goals for 2016, see “Compensation Discussion and Analysis — Key Components of Our NEO Compensation Program — Bonus Compensation".


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In October 2016, cash awards tied to our 2016 annual corporate performance bonus plan were prorated based on the effective date of the Merger and paid out at 200% of “target bonus levels,” which was jointly determined by Fortis and the Company to constitute “target” as used in the Merger Agreement. For the period following the effective date of the Merger, the cash awards were paid out at actual performance against the 2016 performance goals (180% of “target bonus levels”) and prorated for the balance of the year. The cash payments are set forth in the following table.
Name
 
Pre-Merger
 
Post-Merger
Linda H. Blair
 
$
966,436

 
$
277,965

Gretchen L. Holloway
 
135,364

 
32,972

Jon E. Jipping
 
790,148

 
192,467

Daniel J. Oginsky
 
665,802

 
162,178

Christine Mason Soneral
 
275,450

 
420,140

Joseph L. Welch
 
2,013,540

 
—

Rejji P. Hayes
 
$
314,800

 
$
—

____________________________
(a)
To address cutback language in their employment agreements that could have caused them to be treated differently than the other NEOs, the employment agreements with Ms. Mason Soneral and Mr. Hayes were amended to have their annual bonus for 2016 (with the exception of the total shareholder return component which was paid out pursuant to the terms of the Merger Agreement) payable in the ordinary course in accordance with their respective employment agreement and the Company’s past practices based on actual 2016 performance. Because Mr. Hayes resigned from his position with the Company as of November 25, 2016, the Company was not required to pay to him the post-Merger portion of the annual corporate performance bonus in February 2017 to which he would otherwise have been entitled.
(b)
In connection with Mr. Welch’s retirement, he received all of his 2016 annual corporate performance bonus in 2016.
(5)
All amounts reported in this column pertain to the tax-qualified defined benefit pension plan and two supplemental nonqualified, noncontributory retirement plans maintained by the Company. None of the income on nonqualified deferred compensation was above-market or preferential. Variations in the amounts from year to year reflect an additional year of service and pay changes used in the accrued benefit, as well as changes in assumptions on which the benefits are calculated, for which the formula has not been materially revised. The discount rate used for the present value of accumulated benefits was 4.05% in 2014, 4.44% in 2015 and 4.15% in 2016 causing the amounts to fluctuate down from 2014 to 2015 and back up in 2016. Mr. Welch’s change in pension value increased most significantly due to the year over year change in his MSBP benefit which increased due to an additional 15 months of service and higher average final compensation, along with one less year of discounting as he retired during 2016.
(6)
All Other Compensation includes amounts for auto allowance, financial, estate and legal planning, income tax return preparation, annual physical, club memberships, event tickets, personal liability insurance, home security system, personal use of company aircraft and for other benefits such as Company contributions on behalf of the NEOs pursuant to the matching component of the Savings and Investment Plan, as well as any reimbursements for income taxes related to the inclusion of the value of the payment by the Company of these perquisites and payments associated with Mr. Welch’s retirement. Perquisites have been valued for purposes of these tables on the basis of the aggregate incremental cost to the Company. The incremental cost of the personal use of the Company aircraft was determined based upon the Company’s expenses incurred in connection with the actual costs of maintenance, landing, parking, crew and catering and estimated fuel costs relating to Mr. Welch’s hours of use of the plane. Fuel expense was determined by calculating the average fuel cost for the month and the average amount of fuel used per hour. Mr. Welch received a lump sum severance payment of $1,300,000, made pursuant to his October 2016 letter agreement in exchange for, among other items, transition services, waiving his potential right to receive certain post-retirement severance payments under the employment agreement and a general release of any claims


114

against the Company. Director compensation relates to compensation Mr. Welch received for his service as chairman and director after his retirement. Mr. Welch remained on the Board and became a non-employee director upon his retirement on November 1, 2017. These benefits and perquisites for 2016, 2015 and 2014 are itemized in the table below as required by applicable SEC rules.
Name
 
Year
 
401(k) Match
 
Tax Reimbursements
 
Personal Use of Company Aircraft
 
Other Retirement Compensation
 
Director Compensation
 
Other Benefits
 
Total
Linda H. Blair
 
2016
 
$
14,300

 
$
—

 
$
—

 
$
—

 
$
—

 
$
27,001

 
$
41,301

 
2015
 
14,300

 
—

 
—

 
—

 
—

 
23,690

 
37,990

 
2014
 
13,950

 
—

 
—

 
—

 
—

 
24,638

 
38,588

Gretchen L. Holloway
 
2016
 
14,300

 
—

 
—

 
—

 
—

 
17,012

 
31,312

Jon E. Jipping
 
2016
 
15,900

 
—

 
—

 
—

 
—

 
21,369

 
37,269

 
2015
 
14,300

 
—

 
—

 
—

 
—

 
21,710

 
36,010

 
2014
 
13,950

 
—

 
—

 
—

 
—

 
22,329

 
36,279

Daniel J. Oginsky
 
2016
 
14,300

 
—

 
—

 
—

 
—

 
21,197

 
35,497

 
2015
 
14,300

 
—

 
—

 
—

 
—

 
12,569

 
26,869

 
2014
 
13,950

 
—

 
—

 
—

 
—

 
12,020

 
25,970

Christine Mason Soneral
 
2016
 
14,300

 
—

 
—

 
—

 
—

 
21,375

 
35,675

 
2015
 
13,950

 
—

 
—

 
—

 
—

 
—

 
13,950

Joseph L. Welch
 
2016
 
15,900

 
72,955

 
125,141

 
1,300,000

 
24,865

 
36,675

 
1,575,536

 
2015
 
15,900

 
157,704

 
160,025

 
—

 
—

 
43,900

 
377,529

 
2014
 
15,600

 
156,386

 
164,476

 
—

 
—

 
39,253

 
375,715

Rejji P. Hayes
 
2016
 
14,300

 
—

 
—

 
—

 
—

 
14,126

 
28,426

 
2015
 
14,300

 
—

 
—

 
—

 
—

 
17,627

 
31,927

 
2014
 
$
13,950

 
$
—

 
$
—

 
$
—

 
—

 
$
20,420

 
$
34,370

We purchase tickets to various sporting, civic, cultural, charity and entertainment events. We use these tickets for business development, partnership building, charitable donations and community involvement. If not used for business purposes, we may make these tickets available to employees, including the NEOs, as a form of recognition and reward for their efforts. Because such tickets have already been purchased, we do not believe that there is any aggregate incremental cost to the Company, if a NEO uses a ticket for personal purposes.
The All Other Compensation column does not include payments made for purposes of settling outstanding options and share-based awards at the closing of the Merger as described under “Compensation Discussion and Analysis — Merger Agreement and the Merger.” For a description of the amounts paid, see “Option Exercises and Stock Vested.”

(7)
Ms. Blair became President and Chief Executive Officer in November 2016.
(8)
Ms. Holloway became Vice President, Interim Chief Financial Officer and Treasurer in October 2016. In accordance with SEC rules, we have excluded Ms. Holloway’s compensation for 2014 and 2015 as she was not an executive officer in those years.
(9)
Mr. Oginsky was named Executive Vice President and Chief Administrative Officer in May 2016.
(10)
Ms. Mason Soneral became Senior Vice President and General Counsel in February 2015. In accordance with SEC rules, we have excluded Ms. Mason Soneral’s compensation for 2014 as she was not an executive officer in that year.
(11)
Mr. Welch retired from the Company in November 2016. Mr. Welch remains a director and serves as Chairman of the Company’s Board of Directors.


115

(12)
In May 2016, Mr. Hayes was named Executive Vice President and Chief Financial Officer. Mr. Hayes left the Company in November 2016.
Grants of Plan-Based Awards
The following table sets forth information concerning each grant of an award made to a NEO during 2016.
Grants of Plan-Based Awards Table
Name
 
Grant Date
 
Estimated Future Payouts Under Non-Equity Incentive Plan Awards
 
All Other Stock Awards: Number of Shares of Stock or Units (#)
 
Grant Date Fair Value of Stock and Option Awards ($)(2)
 
 
Threshold ($)
 
Target ($)(1)
 
Maximum ($)(1)
 
 
(a)
 
(b)
 
(c)
 
(d)
 
(e)
 
(i)
 
(j)
Linda H. Blair
 
5/19/2016
 
—

 
$
—

 
$
—

 
$
24,448

 
$
1,074,490

 
 
 
—

 
725,000

 
1,450,000

 
—

 
—

Gretchen L. Holloway
 
5/19/2016
 
—

 
—

 
—

 
3,180

 
139,761

 
 
 
 
 
86,000

 
172,000

 
—

 
—

Jon E. Jipping
 
5/19/2016
 
—

 
—

 
—

 
19,989

 
878,517

 
 
 
 
 
502,000

 
1,004,000

 
—

 
—

Daniel J. Oginsky
 
5/19/2016
 
—

 
—

 
—

 
16,843

 
740,250

 
 
 
 
 
423,000

 
846,000

 
—

 
—

Christine Mason Soneral
 
5/19/2016
 
—

 
—

 
—

 
13,936

 
612,487

 
 
 
 
 
350,000

 
700,000

 
—

 
—

Joseph L. Welch
 
5/19/2016
 
—

 
—

 
—

 
60,542

 
2,660,821

 
 
 
 
 
1,279,250

 
2,558,500

 
—

 
—

Rejji P. Hayes
 
5/19/2016
 
—

 
—

 
—

 
15,927

 
$
699,992

 
 
 
 
 
$
400,000

 
$
800,000

 
$
—

 
$
—

____________________________
(1)
The amount shown in Column (d) represents the potential payout for the annual corporate performance bonus based on “target bonus levels” and assumes maximum achievement of all bonus goals other than the TSR goal and no achievement of the TSR goal. The amount payable assuming maximum achievement of all goals is set forth in column (e). Actual dollar amounts paid are disclosed and reported in the Summary Compensation Table as Non-Equity Incentive Plan Compensation. For more information regarding the annual corporate performance bonuses, see “Compensation Discussion and Analysis — Key Components of Our NEO Compensation Program — Bonus Compensation — Annual Corporate Performance Bonus.”
(2)
Grant Date Fair Value consists of restricted stock awarded under the 2015 LTIP, recorded at fair value at the date of grant, which was $43.95 per share.
The Committee has established bonus targets as a percentage of the base salary for each NEO in consideration of benchmarking data on total cash compensation, the importance of the NEO’s position to the success of the Company, our need to create meaningful incentives to enhance performance and the culture of teamwork that makes our company successful. The Committee did not have a pre-established targeted allocation of cash compensation.
The Committee had the power to grant stock options, restricted stock, restricted stock units and performance based awards in the form of equity or cash under the 2015 LTIP with the terms of each award set forth in a written agreement with the recipient. Equity-based grants made in 2016 to the NEOs were made under the 2015 LTIP pursuant to terms stated in a restricted stock award agreement.
The 2016 restricted stock award agreements provided that, subject to the Merger Agreement, so long as the grantee remains employed by us, the restricted stock fully vests upon the earlier of (i) the third anniversary of the grant date (ii) the grantee's death or permanent disability, or (iii) the occurrence of a “Change in Control


116

Termination” (as defined in the 2015 LTIP). If the Merger occurred, the restricted stock would immediately vest, and would be cancelled and converted into the right to receive an amount in cash equal to the product of (x) the total number of shares subject to such restricted stock award multiplied by (y) the cash value of the Merger consideration (later determined to be $45.72), as provided in Section 2.2(b) of the Merger Agreement. If the Merger did not occur and employment was terminated prior to the vesting date for any reason other than death, disability, Retirement (as defined in the 2015 LTIP) or Change in Control Termination, the remaining unvested shares would be canceled unless the Committee, in the exercise of its authority under the 2015 LTIP, modified the vesting date in connection with the termination. If the grantee attained age 65 prior to the vesting date while continuing to be employed by the Company, the stock would have become vested (i) as of the date the grantee becomes 65, in increments of 33-1/3% of such shares in respect of each one year anniversary (if any) of the date of the grant agreement that occurred prior to the grantee attaining such age, and (ii) in increments of 33-1/3% of such shares as of each one year anniversary of the date of the agreement that occurred after the grantee attained such age until all shares have fully vested (provided that grantee continues to be employed by the Company as of each such anniversary). The restricted stock award agreements also provided that restricted stock issued to the grantee generally could not be transferred by the grantee prior to vesting and that grantees otherwise had all rights of holders of our common stock.
Outstanding Equity Awards at Fiscal Year-End
The NEOs did not have any outstanding equity awards as of December 31, 2016. Pursuant to the Merger Agreement, all outstanding stock option, restricted stock and performance share awards vested and were cashed out as of immediately prior to the effective date of the Merger. Please see “Compensation Discussion and Analysis — Merger Agreement” for further details.
Option Exercises and Stock Vested
The following table provides information with respect to options exercised by the NEOs during 2016 and shares of restricted stock and performance shares held by the NEOs that vested during 2016. The table also includes amounts paid by the Company pursuant to the Merger Agreement to cash out options, restricted stock and performance shares held immediately prior to the effective time of the Merger.
Option Exercises and Stock Vested Table
 
 
Option Awards (3)
 
Stock Awards (3)
Name
 
Number of Shares Acquired on Exercise (#)
 
Value Realized on Exercise ($) (1)
 
Number of Shares Acquired on Vesting (#)
 
Value Realized on Vesting ($) (2)
(a)
 
(b)
 
(c)
 
(d)
 
(e)
Linda H. Blair
 
$
737,800

 
$
16,157,448

 
$
80,138

 
$
3,648,382

Gretchen L. Holloway
 
11,977

 
840,131

 
13,482

 
615,474

Jon E. Jipping
 
556,283

 
11,730,528

 
54,396

 
2,982,761

Daniel J. Oginsky
 
330,649

 
6,125,131

 
53,826

 
2,452,260

Christine Mason Soneral (4)
 
57,884

 
1,167,080

 
44,179

 
2,017,404

Joseph L. Welch
 
859,844

 
17,817,645

 
204,674

 
9,289,702

Rejji P. Hayes (4)
 
$
65,744

 
$
739,895

 
$
41,858

 
$
3,702,669

____________________________
(1)
Equals the stock price on the NYSE on the exercise date minus the option exercise price multiplied by the number of shares acquired on exercise.
(2)
Equals the stock price on the NYSE on the vesting date multiplied by the number of shares acquired on vesting.
(3)
The table below reflects the amounts paid to cash out outstanding equity awards in accordance with the Merger Agreement. All unvested options, restricted shares and performance shares became vested immediately prior to the effective time of the Merger pursuant to the Merger Agreement. Options were cashed out at the difference between $45.72 (the cash value of the Merger consideration paid to


117

shareholders) and the option exercise price. Restricted stock and performance shares were cashed out at $45.72 per share.
 
 
Option Awards
 
Stock Awards
Name
 
Number of Shares (#)
 
Value Realized ($)
 
Number of Shares (#)
 
Value Realized($)
(a)
 
(b)
 
(c)
 
(d)
 
(e)
Linda H. Blair
 
$
710,554

 
$
15,248,633

 
$
69,551

 
$
3,179,907

Gretchen L. Holloway
 
5,284

 
51,243

 
12,846

 
587,331

Jon E. Jipping
 
556,283

 
11,730,528

 
45,744

 
2,599,910

Daniel J. Oginsky
 
330,649

 
6,125,131

 
47,916

 
2,190,742

Christine Mason Soneral
 
20,734

 
709,209

 
42,517

 
1,943,860

Joseph L. Welch
 
836,570

 
17,051,737

 
162,463

 
7,427,826

Rejji P. Hayes
 
$
65,744

 
$
739,895

 
$
40,262

 
$
1,840,793

(4)
To address cutback language in the employment agreements of Ms. Mason Soneral and Mr. Hayes, the agreements were amended, pursuant to which a portion of their performance shares were canceled. Ms. Mason Soneral’s amendment provided that she will receive total retention payments of $162,399 payable in five equal installments to be paid on the first payroll date following the first day of each fiscal quarter beginning January 1, 2017, contingent on her continued service to the Company or its affiliates on each applicable payment date. Mr. Hayes’ agreement contained a similar provision but his right to such payments was forfeited upon his resignation from the Company.
Pension Benefits
The following table provides information with respect to each pension benefit plan that provides for payments or other benefits at, following or in connection with retirement. Those plans are the International Transmission Company Retirement Plan (the “Qualified Plan”), the MSBP and the ESRP.


118

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. Blair
 
Cash Balance Component
 
22.58

 
$
329,464

 
N/A

 
ESRP Shift
 
N/A

 
33,974

 
N/A

 
        Total Qualified Plan
 
 
 
363,438

 
N/A

 
ESRP
 
13.82

 
1,236,657

 
N/A

Gretchen Holloway
 
Cash Balance Component
 
12.95

 
195,764

 
N/A

 
        Total Qualified Plan
 
 
 
195,764

 
N/A

 
ESRP
 
1.91

 
60,112

 
N/A

Jon E. Jipping
 
Traditional Component
 
26.03

 
1,190,011

 
N/A

 
        Total Qualified Plan
 
 
 
1,190,011

 
N/A

 
ESRP
 
11.92

 
1,078,432

 
N/A

Daniel J. Oginsky
 
Cash Balance Component
 
12.20

 
254,691

 
N/A

 
        Total Qualified Plan
 
 
 
254,691

 
N/A

 
ESRP
 
12.00

 
823,419

 
N/A

Christine Mason Soneral
 
Cash Balance Component
 
9.29

 
194,003

 
N/A

 
        Total Qualified Plan
 
 
 
194,003

 
N/A

 
ESRP
 
9.28

 
366,614

 
N/A

Joseph L. Welch
 
Cash Balance Component
 
N/A

 
N/A

 
287,900

 
Special Annuity Credit
 
10.00 (3)

 
1,588,184

 
21,685

 
      Total Qualified Plan
 
 
 
1,588,184

 
309,585

 
MSBP
 
46.00

 
48,117,216

 
N/A

Rejji P. Hayes

 
Cash Balance Component
 
4.86

 
99,755

 
N/A

 
       Total Qualified Plan
 
 
 
99,755

 
N/A

 
ESRP
 
4.86

 
163,303

 
N/A

____________________________
(1)
Credited service is estimated as of December 31, 2016 and represents the service reflected in the determination of benefits. For determining vesting, service with DTE Energy is counted for all plans shown in the table except for the ESRP, as explained below.
For Ms. Blair and Mr. Jipping, the credited service for the traditional and cash balance components of the Qualified Plan includes service with DTE Energy. The Company began operations on February 28, 2003, following its acquisition of ITCTransmission from DTE Energy. As of that date, the benefits from DTE Energy’s qualified plan that had accrued, as well as the associated assets from DTE Energy’s pension trust, were transferred to the Company’s plan. Therefore, even though DTE Energy service is included in determining the benefits under the traditional and cash balance components of the Qualified Plan, the benefits associated with this additional service do not represent a benefit augmentation, but rather a transfer of benefit liability and associated assets from DTE Energy’s qualified plan to the Qualified Plan. With respect to the ESRP, credited service includes Company service only for the period during which the NEO was an ESRP participant.
Mr. Welch’s credited service for the Qualified Plan only includes service with the Company because he retired under DTE Energy’s qualified plan concurrent with commencing employment with the Company. As a result, unlike the other NEOs, his benefits under DTE Energy’s qualified plan were not transferred to the Qualified Plan. Mr. Welch also retired under DTE Energy’s Management Supplemental Benefit Plan, though with lower benefits than he would have earned with additional service. In order to compensate Mr. Welch for the value of benefits he would have received had he remained with DTE Energy, the Company agreed to establish its MSBP such that benefits would be calculated including service with DTE Energy, with the


119

resulting amount offset by the benefits he is receiving from DTE Energy. We estimate that $6.6 million of the Present Value of Accumulated Benefit is the value of the augmentation of benefits resulting from including Mr. Welch’s 32 years of service with DTE Energy.
(2)
The “Present Value of Accumulated Benefit” is the estimated lump-sum equivalent value measured as of December 31, 2016 (the “measurement date” used for financial accounting purposes) of the benefit that was earned as of that date. Certain benefits are payable as an annuity only, not as a lump sum, and/or may not be payable for several years in the future. The values reflected are based on several assumptions. The date at which the present values were estimated was December 31, 2016. The rate at which future expected benefit payments were discounted in calculating present values was 4.15%, the same rate used for fiscal year-end 2016 financial accounting disclosure of the Qualified Plan. The future annual earnings rate on account balances under the cash balance and ESRP shift components of the Qualified Plan, and for ESRP benefits, was assumed to be 2.35% for 2017 and 4.5% thereafter.
We assumed no NEOs would die or become disabled prior to retirement, or terminate employment with us prior to becoming eligible for benefits unreduced for early retirement. The assumed retirement age for each executive was generally the earliest age at which benefits unreduced for early retirement were available under the respective plans. For the traditional component of the defined benefit plan, that age is the earlier of (1) age 58 with 30 years of service (including service with DTE Energy), or (2) age 60 with 15 years of service. For consistency, we generally use the same assumed retirement commencement age for other benefits, including benefits expressed as an account value where the concept of benefit reductions for early retirement is not meaningful. The assumed retirement benefit commencement ages for the respective NEOs were as follows:
◦
Ms. Blair:        Age 58
◦
Ms. Holloway    Age 58
◦
Mr. Jipping:        Age 58
◦
Mr. Oginsky        Age 58
◦
Ms. Mason Soneral    Age 58
◦
Mr. Welch:        Actual retirement was November 1, 2016
◦
Mr. Hayes        Age 58 for the qualified plan and June 1, 2017 for the ESRP
Post-retirement mortality was assumed to be in accordance with the RP-2014 table projected for future mortality improvements with modified MP-2014 generational scale. Benefits under the traditional component of the Qualified Plan were assumed to be paid as a monthly annuity payable for the lifetime of the employee. Under the MSBP, benefits are payable for Mr. Welch’s life with a minimum payment period of 15 years guaranteed. For all other benefits, payment was assumed to be as a single lump sum, although other actuarially equivalent forms are available.
(3)    A maximum of 10 years of service is counted for purposes of the Special Annuity Credit.
We maintain one tax-qualified noncontributory defined benefit pension plan and two supplemental nonqualified, noncontributory defined benefit retirement plans. First, we maintain the Qualified Plan, which provides funded, tax-qualified benefits up to the limits on compensation and benefits under the Internal Revenue Code. Generally, all of our salaried employees, including the NEOs, are eligible to participate.
Second, we maintain the MSBP, in which Mr. Welch is the only participant. The MSBP provides additional retirement benefits that are not tax-qualified.
Third, we maintain the ESRP, in which Mses. Blair, Holloway and Mason Soneral and Messrs. Hayes, Jipping and Oginsky participate. The ESRP provides additional retirement benefits which are not tax qualified.


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The following describes the Qualified Plan, the MSBP, and the ESRP, and pension benefits provided to the NEOs under those plans.
Qualified Plan
There are two primary retirement benefit components of the Qualified Plan. Each NEO earns benefits from the Company under only one of these primary components.
Because our first operating utility subsidiary was acquired from DTE Energy, a component of the Qualified Plan bears relation to the DTE Energy Corporation Retirement Plan (the “DTE Plan”). Generally, persons who were participants in the “traditional component” of the DTE Plan as of February 28, 2003 (the date ITCTransmission was acquired from DTE Energy) earn benefits under the traditional component of our Qualified Plan. All other participants earn benefits under the cash balance component. Mr. Welch began receiving retirement benefits under the traditional component of the DTE Plan before beginning his employment with us, and is earning benefits under the cash balance component of the Qualified Plan. In addition to the traditional and cash balance components, Mr. Welch has earned a special annuity credit described below, and Ms. Blair has benefits under the ESRP shift, also described below.
Benefits under the Qualified Plan are funded by an irrevocable tax-exempt trust. A NEO’s benefit under the Qualified Plan is payable from the assets held by the tax-exempt trust.
NEOs become fully vested in their normal retirement benefits described below with 3 years of service, including service with DTE Energy, or upon attainment of the plan’s normal retirement age of 65. If a NEO terminates employment with less than 3 years of service, the NEO is not vested in any portion of his or her benefit.
Traditional Component of Qualified Plan
Mr. Jipping participates in the traditional component of the Qualified Plan. The benefits are determined under the following formula, stated as an annual single life annuity payable in equal monthly installments at the normal retirement age of 65: 1.5% times average final compensation times credited service up to 30 years, plus 1.4% times average final compensation times credited service in excess of 30 years. Credited service includes service with DTE Energy. Although benefits under the formula are defined in terms of a single life annuity, other annuity forms (e.g., joint and survivor benefits) are available that have the same actuarial value as the single life annuity benefit. The benefits are not payable in the form of a lump sum.
Average final compensation is equal to one-fifth of the NEO’s salary (excluding any bonuses or special pay) during the 260 weeks of credited service, not necessarily consecutive, at any time during the NEO’s employment that results in the highest average.
Benefits provided under the Qualified Plan are based on compensation up to a compensation limit under the Internal Revenue Code (which was $265,000 in 2016, and is indexed in future years). In addition, benefits provided under the Qualified Plan may not exceed a benefit limit under the Internal Revenue Code (which was $210,000 payable as a single life annuity beginning at normal retirement age in 2016).
NEOs may retire with a reduced benefit as early as age 45 after 15 years of credited service. If a NEO has 30 years of credited service at retirement, the benefit that would be payable at normal retirement age is reduced for commencement ages below 58. The percentage of the normal retirement benefit payable at sample commencement ages is as follows:
Age 58 and older:    100%
Age 55:             85%
Age 50:             40%
If a NEO has less than 30 years of credited service at retirement, the benefit that would be payable at normal retirement age is reduced for commencement ages below age 60. The percentage of the normal retirement benefit payable at sample commencement ages is as follows:


121

Age 60 and older:    100%
Age 55:             71%
Age 50:             40%
If a NEO terminates employment prior to earning 15 years of credited service, the annuity benefit may not commence prior to attaining age 65. If the NEO terminates employment after earning 15 years of credited service but below age 45, the benefit may commence as early as age 45. The percentage of the normal retirement benefit payable at sample commencement ages is as follows:
Age 65 and older:    100%
Age 60:            58%
Age 55:             36%
Age 50:             23%
Mr. Jipping’s annual accrued benefit payable monthly as an annuity for his lifetime, beginning at age 65, is approximately $101,100. He is fully vested.
Cash Balance Component of Qualified Plan
Mses. Blair, Holloway and Mason Soneral and Messrs. Welch, Hayes and Oginsky participate in the cash balance component of the Qualified Plan. The benefits are stated as a notional account value.
Each year, a NEO’s account is increased by a “contribution credit” equal to 7% of pay. For this purpose, pay is equal to base salary plus bonuses and overtime up to the same compensation limit as applies under the traditional component of the Qualified Plan ($265,000 in 2016). Each year, a NEO’s account is also increased by an “interest credit” based on 30-year Treasury rates.
Upon termination of employment, a vested NEO may elect full payment of his or her account. Alternate forms of benefit (e.g., various forms of annuities) are available as well that have the same actuarial value as the account.
Mses. Blair, Holloway and Mason Soneral and Mr. Oginsky are entitled to immediate payment of their account value on termination of employment, even if before normal retirement age. Ms. Blair’s estimated account value as of year-end 2016 is approximately $324,000, Ms. Holloway’s is approximately $190,000, Ms. Mason Soneral’s is approximately $189,000, and Mr. Oginsky’s is approximately $248,000. Mr. Welch received a lump sum payment of the full value of his account $287,900 upon his retirement in November 2016. Mr. Hayes is fully vested in the Cash Balance Plan and has not commenced his benefit. The estimated account value at year-end 2016 was $99,755.
Special Annuity Credit for Mr. Welch in the Qualified Plan
In addition to his cash balance account, Mr. Welch has earned an additional benefit in the Qualified Plan. This benefit is stated as a single life annuity payable in equal monthly installments, equal to $10,000 times years of credited service after February 28, 2003 up to ten years of credited service (i.e., the maximum benefit is $100,000 per year commencing at normal retirement age). Other annuity forms are available that are actuarially equivalent to the single life annuity.
Because Qualified Plan benefits are offset against the otherwise determined MSBP benefits (see below), the effect of this benefit is to shift benefits from the MSBP, a nonqualified plan, to the Qualified Plan, which affords certain tax benefits to the Company and Mr. Welch. As of year-end 2013, Mr. Welch was eligible to retire and receive the maximum annual benefit of $100,000 commencing at normal retirement age. Mr. Welch has commenced this benefit upon his retirement in the form of a Single Life Annuity with an annual benefit of $130,100 reflecting an actuarial increase from the normal retirement age to his actual retirement age.



122

ESRP Shift Benefit in Qualified Plan
The ESRP provides notional account accruals similar to the cash balance component of the Qualified Plan. The “compensation credit” to the NEO’s notional account, analogous to the contribution credit in the cash balance component of the Qualified Plan, is equal to 9% of base salary plus actual bonus earned under the Company’s annual bonus plan. The “investment credit,” analogous to the interest credit in the cash balance component of the Qualified Plan, is similarly based on 30-year Treasury rates.
The ESRP shift benefit is an amount that would otherwise be payable from the ESRP, but is instead being paid from the Qualified Plan, subject to applicable qualified plan legal limits on the ability to discriminate in favor of highly paid employees. The NEO’s cash balance account is increased by any amounts shifted from the ESRP. As with Mr. Welch’s special annuity credit, the purpose of the benefit is to provide the NEOs and the Company the tax advantages of providing benefits through a qualified plan.
Ms. Blair has received ESRP shift additions to her Qualified Plan cash balance account. There was no shift of compensation credits for 2016, although previous shifts have continued to earn interest credits. As of year-end 2016, her ESRP shift balance was approximately $33,000.
Management Supplemental Benefit Plan
The benefit provided by the MSBP to Mr. Welch is payable as an annuity beginning on the earliest date following termination of employment that is permitted under Section 409A of the Internal Revenue Code (relating to the taxation of deferred compensation). The purpose of the MSBP is to provide an overall target level of benefits based on all of Mr. Welch’s years of service, including with DTE Energy. The MSBP benefit is equal to this overall target offset by all of Mr. Welch’s benefits earned under the Qualified Plan, the DTE Plan, and DTE Energy’s Management Supplemental Benefit Plan, a nonqualified plan.
The MSBP target before offsets, expressed as an annual single life annuity with 15 years of payments guaranteed commencing at age 60 (the MSBP normal retirement age) or later, is equal to: (1) 60% plus 0.5% for each year of total service in excess of 25 years, times (2) “average final compensation.”
Mr. Welch commenced his MSBP benefit on November 1, 2016 with the first six months of payment delayed until May 2, 2017. The life annuity with 15 years of guaranteed payments is the only form of benefits payable under the plan. A lump sum is not available.
“Average final compensation” is equal to one-fifth of Mr. Welch’s compensation during the 260 weeks, not necessarily consecutive, of Company service that results in the highest average. Compensation is equal to salary plus any bonuses, excluding Special Bonus Amounts paid after May 17, 2006 under the Special Bonus Plan and amounts paid under Mr. Welch’s retention compensation agreement. Unlike the Qualified Plan, for the MSBP there is no limit on the amount of pay taken into account.
For purposes of calculating average final compensation, amounts paid by DTE Energy are considered in selecting the highest 260 weeks. Further, each bonus payment that is considered compensation is mapped to the single week it was paid before the highest 260 weeks are selected. Therefore, although compensation is averaged over the number of weeks in 5 years, the average final compensation includes well over 5 years of bonuses.
As of December 31, 2016, Mr. Welch has retired, and he will receive an annual MSBP benefit of approximately $3,486,000 after offsets, payable as an annuity for his lifetime with a minimum payment period of 15 years guaranteed.
The MSBP is funded with a Rabbi Trust, which we cannot use for any purpose other than to satisfy the benefit obligations under the MSBP, except in the event of the Company’s bankruptcy, in which case the assets are available to general creditors.
Executive Supplemental Retirement Plan
The ESRP is a nonqualified retirement plan. Only selected executives participate, including Mses. Blair, Mason Soneral, and Holloway, and Messrs. Hayes, Jipping, and Oginsky. Mr. Welch does not participate. The purpose of the ESRP is to promote the success of the Company and its subsidiaries by providing the ability to attract and retain talented executives by providing such designated executives with additional retirement benefits.


123

The ESRP resembles the cash balance component of the Qualified Plan in that benefits are expressed as a notional account value and the vested account balance is payable as a lump sum on termination of employment, although an installment option of equivalent value is also available.
Each year, a NEO’s account is increased by a “compensation credit” equal to 9% of pay. For this purpose, pay is equal to base salary plus bonuses under the Company’s annual bonus plan. There is no limit on compensation that may be taken into account as in the Qualified Plan. Each year, a NEO’s account is also increased by an “investment credit” equal to the same earnings rate as the interest credit in the cash balance component of the Qualified Plan, based on 30-year Treasury rates.
The plan has been in effect since March 1, 2003. Vesting occurs at 20% for each year of participation. Mses. Blair, Mason Soneral, and Holloway, and Messrs. Jipping and Oginsky are fully vested. Pursuant to the terms of the plan, Mr. Hayes became fully vested at the time of the Merger. The benefit provided by the ESRP to Mr. Hayes is payable as a lump sum beginning on March 1 of the year following termination, but actual payment will be delayed until June 1, 2017 as required under Code Section 409A.

As noted above in the description of the Qualified Plan, a portion of the ESRP account balance may be shifted to the cash balance component of the Qualified Plan each year, as permitted under the rules for qualified plans. Such a shift allows the NEOs to become immediately vested in the account values shifted, and confers certain tax advantages to the NEOs and us. As of December 31, 2016, the ESRP account values, net of the amounts shifted to the Qualified Plan, are as follows:
Ms. Blair
 
$
1,216,887

Ms. Holloway
 
58,200

Mr. Jipping
 
1,074,927

Mr. Oginsky
 
801,021

Ms. Mason Soneral
 
357,141

Mr. Hayes
 
$
164,494

The ESRP is funded with a Rabbi Trust, which we cannot use for any purpose other than to satisfy the benefit obligations under the ESRP, except in the event of the Company’s bankruptcy, in which case the assets are available to general creditors.
Nonqualified Deferred Compensation
We maintain the Executive Deferred Compensation Plan under which nonqualified deferred compensation is permissible. Only selected officers of the Company, including the NEOs, are eligible to participate in this plan and Mr. Welch is the only NEO who has deferred income under this plan. NEOs are allowed to defer up to 100% of their salary, bonus and restricted stock dividends. Investment earnings are based on the various investment options available under the plan, and are selected by the individual NEOs. Distributions will generally be made at the NEO’s termination of employment for any reason. The following table provides information with respect to the plan that allows for the deferral of compensation on a basis that is not tax-qualified. There were no Company contributions, or any NEO contributions, withdrawals, or other distributions pursuant to the plan during 2016.


124

Nonqualified Deferred Compensation Table
Name
 
Aggregate Earnings in Last FY ($)
 
Aggregate Balance at Last FYE ($)
(a)
 
(d)
 
(f)
Linda H. Blair
 
—

 
—

Gretchen L. Holloway
 
 
 
 
Jon E. Jipping
 
—

 
—

Daniel J. Oginsky
 
—

 
—

Christine Mason Soneral
 
 
 
 
Joseph L. Welch (1)
 
$
48,464

 
$
777,679

Rejji P. Hayes
 
—

 
—

____________________________
(1)
None of this amount is reported in the Summary Compensation Table, as none of it is above-market or preferential.
Employment Agreements and Potential Payments Upon Termination or Change in Control
Employment Agreements
As referenced above, we entered into employment agreements with Ms. Blair and Messrs. Jipping, Oginsky and Welch in December 2012 which superseded the employment agreements then in effect. We entered into an employment agreement with Mr. Hayes in October 2014. In February 2015, we entered into employment agreements with Mses. Mason Soneral and Holloway, which in the case of Ms. Mason Soneral, superseded her employment agreement then in effect. The employment agreements are subject to automatic one-year employment term renewals each year beginning on its second anniversary, unless either party provides the other with 30 days’ advance written notice of intent not to renew the employment term. Ms. Blair’s agreement was modified in October 2016 in connection with her appointment as President and Chief Executive Officer and the term of the agreement is now set to expire December 31, 2018, subject to the automatic one-year renewal provision described above. Ms. Mason Soneral’s agreement was modified in October 2016 as described in “Compensation Discussion and Analysis — Employment Agreement Amendments — Mason Soneral and Hayes.” Mr. Welch’s agreement was superseded upon his execution of the letter agreement with the Company dated October 14, 2016. Mr. Hayes’ agreement was modified in October 2016 and terminated upon his resignation on November 25, 2016. The following describes the material terms of the employment agreements, as amended, with the NEOs who remained employed by the Company on December 31, 2016.
The employment agreements provide that each NEO will receive an annual base salary equal to their current base salary, which is subject to annual review and increase by our Board of Directors in its discretion. The employment agreements also provide that NEOs are eligible to receive an annual cash bonus, subject to our achievement of certain performance targets established by our Board of Directors, as detailed in “Compensation Discussion and Analysis”. The employment agreements also provide the NEOs with the right to participate in equity plans, employee benefit plans and retirement plans, including but not limited to welfare plans, retiree welfare benefit plans and defined benefit and defined contribution plans.
In addition, the NEOs’ employment agreements provide for payments by us of certain benefits upon termination of employment. The rights available at termination depend on the situation and circumstances surrounding the terminating event. The terms “Cause” and “Good Reason” are used in the employment agreements of each NEO and an understanding of these terms is necessary to determine the appropriate rights for which a NEO is eligible. The terms are defined as follows:
•
Cause means: a NEO’s continued failure substantially to perform his or her duties (other than as a result of total or partial incapacity due to physical or mental illness) for a period of 10 days following written notice by the Company to the NEO of such failure; dishonesty in the performance of the NEO’s duties; a NEO’s conviction of, or plea of nolo contender to, a crime constituting a felony or misdemeanor involving moral turpitude; willful malfeasance or willful misconduct in connection with a NEO’s duties; any act or omission


125

which is injurious to the financial condition or business reputation of the Company; or violation of the non-compete or confidentiality provisions of the employment agreement.
•
Good reason means: a greater than 10% reduction in the total value of the NEO’s base salary, target bonus, and employee benefits; or if the NEO’s responsibilities and authority are substantially diminished.
If a NEO’s employment is terminated with cause by the Company or by the NEO without good reason, the NEO will generally only receive his or her accrued but unpaid compensation and benefits as of the date of his or her employment termination. If the NEO terminates due to death or disability (as defined in the employment agreements), the NEO (or the NEO’s spouse or estate) would also receive a pro rata portion of his or her current year annual target bonus.
If a NEO’s employment is terminated by the Company without cause or by the NEO for good reason, the NEO will receive the following, subject to the NEO’s execution of a release agreement and commencing generally on the earliest date that is permitted under Section 409A of the Internal Revenue Code:
•
any accrued but unpaid compensation and benefits. The benefits include:
◦
Ms. Blair: cash balance and ESRP shift under the Qualified Plan and vested portion of ESRP balance;
◦
Mr. Jipping: annual benefit under the traditional component of the Qualified Plan and vested portion of ESRP balance; and
◦
Mr. Oginsky, Ms. Mason Soneral and Ms. Holloway: cash balance under the Qualified Plan and vested portion of ESRP balance
•
continued payment of the NEO’s then-current base salary for two years (one year for Ms. Holloway);
•
if the termination is within six months before or two years after a “Change of Control” (as defined in the employment agreements), payment of an amount equal to two times the average of the annual bonuses, that were payable to the NEO for the three fiscal years immediately preceding the fiscal year in which his or her employment terminates, payable in equal installments over the period in which continued base salary payments are made and for Ms. Holloway, continued payment of base salary for an additional year;
•
a pro rata portion of the annual bonus for the year of termination, based upon the Company’s actual achievement of the performance targets for such year as determined under the annual bonus plan and paid at the time that such bonus would normally be paid;
•
eligibility to continue coverage under our active medical, dental and vision plans subject to applicable COBRA rules; if such coverage is elected, we will reimburse the NEO for the shorter of 18 months (12 months for Ms. Holloway), or until the NEO becomes eligible for coverage under another employer-sponsored group plan, in an amount equal to our periodic cost of such coverage for other executives, plus a tax gross-up amount;
•
outplacement services for up to two years; and
•
for Ms. Blair, deemed satisfaction of the eligibility requirements of our Postretirement Welfare Plan for purposes of participation therein; and for Messrs. Jipping and Oginsky, participation in our Postretirement Welfare Plan only if, by the end of their specified severance period, they have achieved the necessary age and service credit otherwise necessary to meet the eligibility requirements. In addition, if we terminate our Postretirement Welfare Plan and, by application of the provisions described in the prior sentence, any of these NEOs would otherwise be entitled to retiree welfare benefits, we will establish other coverage for the NEO or the NEO will receive a cash payment equal to our cost of providing such benefits, in order to assist the NEO in obtaining other retiree welfare benefits.
In addition, while employed by us and for a period of two years after any termination of employment without cause by the Company (other than due to their disability) or for good reason by them and for a period of one year following any other termination of their employment, the NEOs (other than Ms. Holloway) will be subject to certain covenants not to compete with or assist other entities in competing with our business and not to encourage our


126

employees to terminate their employment with us. Ms. Holloway would be subject to these covenants for a period of one year, regardless of the reason for termination of employment, which period may be extended for one additional year at our sole discretion in exchange for continued payment of Ms. Holloway’s base salary during such period. At all times while employed and thereafter, all of the NEOs will also be subject to a covenant not to disclose confidential information.
In the event the NEO becomes subject to excise taxes under Section 4999 of the Internal Revenue Code as a result of payments and benefits received under the employment agreements or any other plan, arrangement or agreement with us, we will pay the NEO only that portion of such payments which are in total equal to one dollar less than the amount that would subject the NEO to the excise tax.
Payments Made in Connection with the Merger
The table below provides a summary of the payments made to the NEOs as a result of the completion of the Merger.
ITC Holdings
Payments Made in Connection with the Merger
12/31/2016
 
 
Linda H. Blair
 
Jon E. Jipping
 
Daniel J. Oginsky
 
Christine Mason Soneral
 
Gretchen L. Holloway
 
Joseph L. Welch
 
Rejji P. Hayes
 
Compensation
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Severance
 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
Target Short-term Bonus
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
Pro Rata Short-term (Annual) Incentive Comp(1)
 
966,436

 
790,148

 
665,802

 
275,450

 
135,364

 
2,013,540

 
314,800

 
Retention Awards(2)
 
276,300

 
225,900

 
190,350

 
457,500

 
60,000

 
—

 
480,000

 
Stock Options(3)
 
15,248,633

 
11,730,528

 
6,125,131

 
250,706

 
51,243

 
17,051,737

 
1,176,938

 
Restricted Stock Awards(3)
 
1,387,318

 
1,134,264

 
955,753

 
790,804

 
167,850

 
3,435,372

 
903,727

 
Performance Shares(4)
 
1,792,590

 
1,465,646

 
1,234,989

 
1,315,456

 
419,481

 
3,992,453

 
1,733,748

 
Benefits and Perquisites
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Retirement Plan
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
ESRP(5)
 
—

 
—

 
—

 
—

 
15,683

 
—

 
31,956

 
Perquisites
 
—

 
—

 
—

 
—

 
—

 
—

 
 
 
Health & Welfare Benefits
 
—

 
—

 
—

 
—

 
—

 
—

 
 
 
Postretirement Welfare Plan
 
—

 
—

 
—

 
—

 
—

 
—

 
 
 
Total Payout:
 
$
19,671,277

 
$
15,346,486

 
$
9,172,025

 
$
3,089,916

 
$
849,621

 
$
26,493,102

 
$
4,641,169

 
________________________
(1)
Reflects pro rata annual bonus payment made in connection with the Merger for the period through October 14, 2016. Remaining annual bonus payments were made at the time that normal annual bonus payments are made and are not included in this table. Ms. Mason Soneral’s and Mr. Hayes’ annual bonus (with the exception of the total shareholder return component which was paid out pursuant to the terms of the Merger Agreement) was payable in the ordinary course in accordance with their respective employment agreement and the Company’s past practices based on actual 2016 performance. See “Employment Agreement Amendments — Mason Soneral and Hayes”. Mr. Welch’s amount represents the full amount of his annual corporate performance bonus.
(2)
For all but Mr. Hayes, includes 100% of retention bonus, 30% of which was paid in 2016 and the remainder of which is due one year after closing subject to the NEO’s continued employment. For Mr. Hayes, the amount shown is the portion he received prior to his resignation. Table also includes $300,000 bonuses paid in 2016 to


127

Ms. Mason Soneral and Mr. Hayes that were contingent on closing the Merger prior to December 31, 2016 and continued employment at the time of the Merger.
(3)
Reflects the cash value paid for outstanding stock options and previously unvested restricted stock awards. The per share amount of the Merger consideration used for purposes of determining the payment amount was $45.72.
(4)
Reflects the cash value paid to holders of previously unvested performance share awards in connection with the Merger. Performance shares vested at 181.25% of target in accordance with the Merger Agreement, together with related dividend equivalents. The per share amount of Merger consideration used for purposes of determining the payment amount was $45.72.
(5)
Reflects the value of the accelerated vesting ESRP account balance in connection with the Merger.
Payments in the Event of Termination
The benefits to be provided to the NEOs as a result of termination under various scenarios are detailed in the tables below. The tables assume that the termination occurred on December 31, 2016. There was no outstanding equity as of December 31, 2016.
Linda H. Blair - Termination Scenarios: Value of Potential Payments
Total Value of Severance, Benefits and Unvested Equity Awards(1)(2)
 
 
Voluntary Resignation
 
Involuntary For Cause
 
Involuntary Not-for-Cause or Voluntary Good Reason
 
Change In Control (pre-tax)(3)
 
Disability
 
Death (pre-retirement)(4)
Compensation
 
 
 
 
 
 
 
 
 
 
 
 
  Cash Severance
 
$
—

 
$
—

 
$
1,450,000

 
$
2,855,674

 
$
—

 
$
—

  Target Short-term Bonus
 
—

 
—

 
—

 
—

 
725,000

 
725,000

  Pro Rata Short-term (Annual) Incentive Comp
 
—

 
—

 
1,244,401

 
1,244,401

 
—

 
—

Retention Awards
 
 
 
 
 
644,700

 
644,700

 
644,700

 
644,700

  Stock Options
 
—

 
—

 
—

 
—

 
—

 
—

  Restricted Stock Awards
 
—

 
—

 
—

 
—

 
—

 
—

  Performance Share Awards
 
—

 
—

 
—

 
—

 
—

 
—

Benefits and Perquisites
 
 
 
 
 
—

 
 
 
 
 
 
  Retirement Plan
 
—

 
—

 
—

 
—

 
—

 
—

  ESRP
 
—

 
—

 
—

 
—

 
—

 
—

  Perquisites
 
—

 
—

 
25,000

 
25,000

 
—

 
—

  Health & Welfare Benefits
 
—

 
—

 
29,524

 
29,524

 
—

 
—

  Postretirement Welfare Plan (5)
 
—

 
—

 
265,819

 
265,819

 
—

 
—

Total Payout:
 
—

 
—

 
$
3,659,444

 
$
5,065,118

 
$
1,369,700

 
$
1,369,700



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

 
$
—

 
$
215,000

 
$
528,342

 
$
—

 
$
—

  Target Short-term Bonus
 
—

 
—

 
—

 
—

 
86,000

 
86,000

  Pro Rata Short-term (Annual) Incentive Comp
 
—

 
—

 
168,337

 
168,337

 
—

 
—

Retention Awards
 
 
 
 
 
140,000

 
140,000

 
140,000

 
140,000

  Stock Options
 
—

 
—

 
—

 
—

 
—

 
—

  Restricted Stock Awards
 
—

 
—

 
—

 
—

 
—

 
—

  Performance Share Awards
 
—

 
—

 
—

 
—

 
—

 
—

Benefits and Perquisites
 
 
 
 
 
 
 
 
 
 
 
 
  Retirement Plan
 
—

 
—

 
—

 
—

 
—

 
—

  ESRP
 
—

 
—

 
—

 
—

 
—

 
—

  Perquisites
 
—

 
—

 
25,000

 
25,000

 
—

 
—

  Health & Welfare Benefits
 
—

 
—

 
18,172

 
18,172

 
—

 
—

Total Payout:
 
—

 
—

 
$
566,509

 
$
879,851

 
$
226,000

 
$
226,000

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

 
$
—

 
$
1,004,000

 
$
2,153,087

 
$
—

 
$
—

  Target Short-term Bonus
 
—

 
—

 
—

 
—

 
502,000

 
502,000

  Pro Rata Short-term (Annual) Incentive Comp
 
—

 
—

 
982,615

 
982,615

 
—

 
—

Retention Awards
 
 
 
 
 
527,100

 
527,100

 
527,100

 
527,100

  Stock Options
 
—

 
—

 
—

 
—

 
—

 
—

  Restricted Stock Awards
 
—

 
—

 
—

 
—

 
—

 
—

  Performance Share Awards
 
—

 
—

 
—

 
—

 
—

 
—

Benefits and Perquisites
 
 
 
 
 
 
 
 
 
 
 
 
  Retirement Plan (6)
 
—

 
—

 
—

 
—

 
—

 
—

  ESRP
 
—

 
—

 
—

 
—

 
—

 
—

  Perquisites
 
—

 
—

 
25,000

 
25,000

 
—

 
—

  Health & Welfare Benefits
 
—

 
—

 
28,630

 
28,630

 
—

 
—

Total Payout:
 
—

 
—

 
$
2,567,346

 
$
3,716,433

 
$
1,029,100

 
$
1,029,100



129

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
 
$
—

 
$
—

 
$
846,000

 
$
1,794,317

 
$
—

 
$
—

  Target Short-term Bonus
 
—

 
—

 
—

 
—

 
$
423,000

 
$
423,000

  Pro Rata Short-term (Annual) Incentive Comp
 
—

 
—

 
$
827,981

 
$
827,981

 
—

 
—

Retention Awards
 
 
 
 
 
444,150

 
444,150

 
444,150

 
444,150

  Stock Options
 
—

 
—

 
—

 
—

 
—

 
—

  Restricted Stock Awards
 
—

 
—

 
—

 
—

 
—

 
—

  Performance Share Awards
 
—

 
—

 
—

 
—

 
—

 
—

Benefits and Perquisites
 
 
 
 
 
 
 
 
 
 
 
 
  Retirement Plan
 
—

 
—

 
—

 
—

 
—

 
—

  ESRP
 
—

 
—

 
—

 
—

 
—

 
—

  Perquisites
 
—

 
—

 
$
25,000

 
$
25,000

 
—

 
—

  Health & Welfare Benefits
 
—

 
—

 
$
27,737

 
$
27,737

 
—

 
—

Total Payout:
 
—

 
—

 
$
2,170,868

 
$
3,119,185

 
$
867,150

 
$
867,150

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

 
$
—

 
$
700,000

 
$
1,030,674

 
$
—

 
$
—

  Target Short-term Bonus
 
—

 
—

 
—

 
—

 
$
350,000

 
$
350,000

  Pro Rata Short-term (Annual) Incentive Comp
 
—

 
—

 
695,590

 
$
695,590

 
—

 
—

Retention Awards
 
 
 
 
 
367,500

 
367,500

 
367,500

 
367,500

  Stock Options
 
—

 
—

 
—

 
—

 
—

 
—

  Restricted Stock Awards
 
—

 
—

 
—

 
—

 
—

 
—

  Performance Share Awards
 
—

 
—

 
—

 
—

 
—

 
—

  280G Cutback
 
—

 
—

 
—

 
$
(97,635
)
 
—

 
—

Benefits and Perquisites
 
 
 
 
 
 
 
 
 
 
 
 
  Retirement Plan
 
—

 
—

 
—

 
—

 
—

 
—

  ESRP
 
—

 
—

 
—

 
—

 
—

 
—

  Perquisites
 
—

 
—

 
25,000

 
$
25,000

 
—

 
—

  Health & Welfare Benefits
 
—

 
—

 
28,511

 
$
28,511

 
—

 
—

Total Payout:
 
—

 
—

 
$
1,816,601

 
$
2,049,639

 
$
717,500

 
$
717,500

____________________________
(1)
All scenarios include the value of severance. Table reflect the remaining 70% of the May 2016 retention program awards under the applicable qualified termination scenarios. There was no outstanding equity as of December 31, 2016. For Ms. Blair, the value of the Postretirement Welfare Plan is additionally included where applicable. The Pension Benefits Table assumes that none of the executives are terminated prior to retirement age and that benefits are paid once retirement commences (age 58 is assumed). All other accrued pension benefits, outside of present value reductions outlined in footnotes (4) and (6), and additional pension benefits upon death, have not been included in these termination scenarios but can be found in the Pension Benefits Table.


130

(2)
Upon any termination of employment, benefits that are accrued but unpaid prior to that event are paid. These benefits are assumed to be $0 in the above table.
(3)
Change in control values include severance amounts reflecting cutbacks to safe harbor value where this is greater than if an excise tax had been paid. Ms. Mason Soneral would be subject to an excise tax at the assumed change in control date; therefore, a cutback in the amount of $97,635 has been reflected. The rate at which future expected benefit payments were discounted in calculating the Postretirement Welfare Plan present values was 4.28%, the same rate used for fiscal year-end 2016 accounting disclosure of the Postretirement Welfare Plan.
(4)
In the event of Mr. Jipping’s termination for death (pre-retirement), his spouse would receive half the 50% joint and survivor annuity under the traditional component of the Qualified Plan, also reduced to reflect a 90% early retirement factor that would apply at age 58 since Mr. Jipping does not have 30 years of service as of December 31, 2016. Under termination for death (pre-retirement), Ms. Blair’s, Ms. Mason Soneral’s, Ms. Holloway’s, and Mr. Oginsky’s Qualified Plan benefits are payable immediately to the surviving spouse (if any) and ESRP benefits are payable to a designated beneficiary or estate. The above termination scenarios do not reflect the reduction in present value of death benefits ($383,208 for Ms. Blair, $666,800 for Mr. Jipping, $29,326 for Mr. Oginsky, $14,487 for Ms. Mason Soneral, and $8,140 for Ms. Holloway) compared to present value in the Pension Benefits Table.
(5)
The value of the Postretirement Welfare Plan benefit is included in involuntary termination not for cause and change in control scenarios since Ms. Blair's employment agreement includes a provision for deemed satisfaction of the eligibility requirements when terminated under these scenarios. It is assumed she would commence her Postretirement Welfare Benefits at age 58.
(6)
The Pension Benefits Table assumes that Mr. Jipping would not be terminated before retirement age and no early retirement reduction was applied. In all termination scenarios, however, a 90% early retirement factor would apply at age 58 because Mr. Jipping has less than 30 years of service as of December 31, 2016. The above table does not reflect the reduction in the present value ($119,001 except for death) due to applying the 90% early retirement factor.
Upon death or disability, a NEO (or his or her estate) receives a pro rata portion of his or her current year target bonus. All balances under the cash balance and ESRP shift components of the Qualified Plan, and the ESRP balance (vested portion only for disability), are immediately payable. If the NEO has 10 years of service after age 45, then the NEO (and his or her spouse) is eligible for retiree medical benefits.
Pursuant to his October 2016 letter agreement, Mr. Welch received a lump sum payment of $1,300,000 in exchange for, among other items, transition services, waiving his potential right to receive certain post-retirement severance payments under the employment agreement and a general release of any claims against the Company reflected under Cash Severance.  In addition, upon termination Mr. Welch received all benefits that were accrued but unpaid, which included the May 2016 bonus. Mr. Welch was retirement eligible at the time of his Voluntary Resignation and therefore is entitled to receive the benefits disclosed in the Pension Benefits Table.  Mr. Welch received a lump sum distribution of his Retirement Plan — Cash Balance Component benefit in November 2016 in the amount of $287,900 and commenced receiving his Retirement Plan — Special Annuity Credit benefit in the amount of $10,842 monthly on November 1, 2016. His MSBP benefit of $290,468 monthly became due beginning on November 1, 2016. Payment of the first six months are delayed until May 2, 2017 pursuant to Code Section 409A.
Mr. Hayes was not entitled to any severance benefits or payments in connection with his resignation. The only payment Mr. Hayes will receive is a lump distribution of his ESRP benefit on June 1, 2017, as a result of the six month delay required under Code Section 409A and at this time has made no election to commence his Retirement Plan — Cash Balance Component benefit.
Director Compensation
The following table provides information concerning the compensation of each person, other than Mr. Welch, who served as a director of the Company during 2016. Mr. Welch’s compensation is set forth in the “Summary Compensation Table”.



131

Director Compensation Table
Name (1)
 
Fees Earned or Paid in Cash ($) (2)
 
Stock Awards ($) (3)
 
Total ($)
(a)
 
(b)
 
(c)
 
(h)
Albert Ernst
 
$
67,292

 
$
63,669

 
$
130,961

Rhys D. Evenden
 
26,835

 
—

 
26,835

Christopher H. Franklin
 
75,209

 
63,669

 
138,878

Edward G. Jepsen
 
75,209

 
63,669

 
138,878

James P. Laurito
 
26,835

 
—

 
26,835

David R. Lopez
 
75,209

 
63,669

 
138,878

Hazel R. O’Leary
 
75,209

 
63,669

 
138,878

Barry V. Perry
 
26,835

 
—

 
26,835

Thomas G. Stephens
 
67,292

 
63,669

 
130,961

G. Bennett Stewart
 
67,292

 
63,669

 
130,961

Lee C. Stewart
 
87,084

 
63,669

 
150,753

____________________________
(1)
Messrs. Evenden, Laurito and Perry were appointed to the Board on October 14, 2016. Ms. O’Leary and Messrs. Ernst, Franklin, Lopez, Stephens, G. Bennett Stewart and Lee Stewart left the Board on October 14, 2016 with the closing of the Merger. Messrs. Ernst and Stephens were reappointed to the Board, effective January 1, 2017.
(2)
Includes annual Board retainer and committee chairmanship retainer, as well as a lead director fee (for Mr. Lee Stewart only).
(3)
Aggregate grant date fair value is computed in accordance with ASC 718. Awards of restricted stock are made quarterly prior to the Merger and recorded at fair value at the date of grant. The values for Ms. O’Leary and Messrs. Ernst, Franklin, Jepsen, Lopez, Stephens, Bennett Stewart and Lee Stewart awards were $63,669 (equivalent to 487 shares at $43.57 per share, 453 shares at $46.82 per share and 457 shares at $46.48 per share). There were no outstanding stock awards as of December 31, 2016.
(4)
The fees payable to Mr. Evenden are made directly to Betchworth Investment Pte. Ltd.
The table below reflects the amounts paid in cash to non-employee directors serving as such at the time of the Merger for unvested restricted stock awards that were vested and paid in accordance with the Merger Agreement in the same manner as described in “Compensation Discussion and Analysis — Merger Agreement and the Merger.”


132

 
 
Stock Awards
Name
 
Number of Shares (#)
 
Value Realized ($)
(a)
 
(d)
 
(e)
Albert Ernst
 
4,528

 
$
207,020

Christopher H. Franklin
 
5,806

 
265,450

Edward G. Jepsen
 
5,806

 
265,450

David R. Lopez
 
4,528

 
207,020

Hazel R. O’Leary
 
5,806

 
265,450

Thomas G. Stephens
 
5,806

 
265,450

G. Bennett Stewart
 
5,806

 
265,450

Lee C. Stewart
 
5,806

 
$
265,450

Under the non-employee director compensation policy prior to the Merger, all non-employee directors were paid an annual cash retainer of $85,000 and an annual equity retainer of restricted stock with a total value of $85,000 (awarded through quarterly grants valued at $21,250 each). In addition, we paid an additional cash retainer of $10,000 annually to the chair of each Board committee and $25,000 annually to our lead director. We did not pay per-meeting fees under the policy. Directors had the discretion to make individual elections to receive anywhere from 50% to 100% of the total annual cash retainer in grants of Company stock with the same vesting provisions as described for restricted stock grants below. Directors were reimbursed for their out-of-pocket expenses in an accountable expense plan.
Under the director compensation policy that applies currently, all non-employee directors are paid an annual cash retainer of $125,000. In addition, we pay an additional cash retainer of $7,500 annually to the chair of each Board committee and $25,000 annually to our chairman. We do not pay per-meeting fees under the policy.
Compensation Committee Interlocks and Insider Participation
During 2016 prior to the closing of the Merger, the Committee consisted of Mr. Stephens as well as David Lopez and Hazel O’Leary, each of whom was an independent director and had no current or former employment relationship with the Company. The Board of Directors was reconstituted as a result of the Merger on October 14, 2016, to consist of Messrs. Welch (our President and Chief Executive Officer through November 1, 2016), Perry, Laurito and Evenden, each of whom also served as a member of the Governance and Human Resources Committee from that date until independent directors were elected and the Board’s committees were reconstituted in January 2017.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.
The following table sets forth certain information regarding the ownership of our common stock and Fortis’ common stock as of February 1, 2017, except as otherwise indicated, by:
•
each of our current directors;
•
each of the persons named in the Summary Compensation Table under Item 11; and
•
all current directors and executive officers as a group.
The number of shares beneficially owned is determined under rules of the SEC and the information is not necessarily indicative of beneficial ownership for any other purpose. Under such rules, beneficial ownership includes any shares as to which the individual has sole or shared voting power or investment power and also any shares which the individual has the right to acquire on February 1, 2017 or within 60 days thereafter through the exercise of any stock option or other right. Unless otherwise indicated, each holder has sole investment and voting power with respect to the shares set forth in the following table:


133

Name of Beneficial Owner
Number of Shares
Beneficially Owned
Percent of Class
Fortis Inc. Number of shares Beneficially Owned
Percent of Class
Joseph L. Welch
—

—
%
1,178,328 (1)
*

Linda H. Blair
—

—
%
53,889

*

Gretchen L. Holloway
—

—
%
3,159

*

Jon E. Jipping
—

—
%
120,000

*

Daniel J. Oginsky
—

—
%
72,631

*

Christine Mason Soneral
—

—
%
—

—

Rejji P. Hayes
—

—
%
1,755

*

Albert Ernst
—

—
%
14,022 (2)

*

Rhys D. Evenden
—

—
%
—

—

Robert A. Elliott
—

—
%
—

—

James P. Laurito
—

—
%
—

—

Barry V. Perry
—

—
%
205,234 (3)

*

Sandra E. Pierce
—

—
%
—

—

Kevin L. Prust
—

—
%
—

—

Thomas G. Stephens
—

—
%
2,098

*

All current directors and executive officers as a group (15 persons)
—

—
%
1,651,106

*

* Less than one percent
____________________________
(1)
The amount shown in the table does not include 534,064 shares beneficially owned by the spouse of Mr. Welch. Mr. Welch has no voting or dispositive power with respect to, and disclaims ownership of such shares.
(2)
Includes 4,234 shares owned by the spouse of Mr. Ernst.
(3)
Includes 28,715 shares owned by the spouse and children of Mr. Perry.
Investment Holdings, which owns all of our outstanding common stock, is 80.1% owned by FortisUS and 19.9% owned by Eiffel. FortisUS is a wholly owned subsidiary of Fortis.
At December 31, 2016, there were no securities authorized for issuance under any compensation plans of ITC Holdings.
ITEM 13.     CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.
CERTAIN TRANSACTIONS
Pursuant to its charter, the Governance and Human Resources Committee is charged with monitoring and reviewing issues involving independence and potential conflicts of interest with respect to our directors and executive officers. The Governance and Human Resources Committee also determines whether or not a particular relationship serves the best interest of the Company and its shareholders and whether the relationship should be continued or eliminated. In addition, our Code of Conduct and Ethics generally forbids conflicts of interest unless approved by the Board or a designated committee.
Although the Company does not have a written policy with regard to the approval of transactions between the Company and its executive officers and directors, each director and officer must annually submit a form to the General Counsel disclosing his or her conflicts or potential conflicts of interest or certifying that no such conflicts


134

of interest exist. Throughout the year, if any transaction constituting a conflict of interest arises or circumstances otherwise change that would cause a director’s or officer’s annual conflict certification to become incorrect, the director or officer must inform the General Counsel of such circumstances. The Governance and Human Resources Committee reviews existing conflicts as well as potential conflicts of interest and determines whether any further action is necessary, such as recommending to the Board whether a director or officer should be requested to offer his or her resignation. Where the Board makes a determination regarding a potential conflict of interest, a majority of the Board (excluding any interested member or members) shall decide upon an appropriate course of action. Additionally, any director or officer who has a question about whether a conflict exists must bring it to the attention of the Company’s General Counsel or Chairperson of the Governance and Human Resources Committee.
Clayton Welch, Jennifer Welch, Jessica Uher and Katie Welch (each of whom is a son, daughter or daughter-in-law of Joseph L. Welch, the Company’s Chairman and former chief executive officer) were employed by us as a Senior Engineer, Fleet Manager, Manager of Corporate and Field Facilities, and Senior Accountant, respectively, during 2016 and continue to be employed by us. These individuals are employed on an “at will” basis and compensated on the same basis as our other employees of similar function, seniority and responsibility without regard to their relationship with Mr. Welch. These four individuals, none of whom resides with or is supported financially by Mr. Welch, received aggregate salary, bonus, long-term incentives and taxable perquisites for services rendered in the above capacities totaling $795,369 during 2016.
DIRECTOR INDEPENDENCE
Based on the absence of any material relationship between them and us, other than their capacities as directors, the Board has determined that Ms. Pierce and Messrs. Ernst, Elliott, Prust and Stephens are “independent” as defined in as the Shareholders Agreement. In addition, our Board has determined that, as the committees are currently constituted, a majority of the members of the Audit and Risk Committee are “independent” as defined in the Shareholders Agreement. None of the directors determined to be independent is or ever has been employed by us. The Company has made charitable contributions of less than $1 million each to organizations with which certain of our directors have affiliations. The Board determined that these contributions would not interfere with the exercise of independent judgment by these directors in carrying out their responsibilities.
An independent director under the Shareholders Agreement is a director who meets all of the following requirements: (a) is elected by the shareholders of Investment Holdings; (b) is designated as an independent director by the Investment Holdings board, the Company’s Board, or the shareholders of Investment Holdings; (c) is not a director that is nominated by Finn Investment Pte Ltd or any successor or permitted assign thereof and appointed as a member of the Investment Holdings board and Company Board in accordance with the Shareholders Agreement; (d) is not and during the three years prior to being designated as an independent director has not been any of the following: (i) a director of FortisUS or any of its affiliates (other than Investment Holdings or the Company); or (ii) an officer or employee of Investment Holdings, the Company, FortisUS or any of their affiliates; and (e) would meet the definition of “independent director” under the New York Stock Exchange Listed Company Manual if such director were a member of the board of directors of Fortis, FortisUS, Investment Holdings, or the Company (assuming, in the case of FortisUS, Investment Holdings and the Company, that such entities were listed on the New York Stock Exchange).
Mr. Elliott serves on the board of directors of UNS Energy Corporation, a wholly owned subsidiary of FortisUS. When determining Mr. Elliott’s independence, the board and shareholders agreed to waive the requirements set forth in the definition of independent director under the Shareholders Agreement which states that a director is not and during the three years prior to being designated as a director of the company has not served as a director of FortisUS or any of its affiliates.
Mr. Ernst was a member of the law firm Dykema Gossett PLLC until he retired in August 2014. We made payments for legal services to the Dykema law firm amounting to less than 5% of its gross revenues during each of the last three calendar years. However, as a former member of Dykema who has no consulting or employment relationship with that firm, Mr. Ernst has no financial or other interest in payments made to that firm following his retirement. Our Board considered this former relationship when determining that Mr. Ernst is independent and determined that this relationship was not material and was unlikely to affect his ability to act as an independent board member.


135

ITEM 14.     PRINCIPAL ACCOUNTANT FEES AND SERVICES.
The following table provides a summary of the aggregate fees incurred for Deloitte’s services in 2016 and 2015:
 
2016
2015
Audit fees (1)
$
1,866,000

$
1,855,636

Audit-related fees (2)
924,000

113,239

Tax fees (3)
753,000

209,689

All other fees (4)
10,000

5,000

Total fees
$
3,553,000

$
2,183,564

____________________________
(1)
Audit fees were for professional services rendered for the audit of our consolidated financial statements and internal controls and reviews of the interim consolidated financial statements included in quarterly reports and services that are normally provided by Deloitte in connection with statutory and regulatory filing engagements.
(2)
Audit-related fees were for assurance and related services that are reasonably related to the performance of the audit or review of our consolidated financial statements and are not reported under “Audit Fees.” These services include due diligence support relating to merger and acquisition activity and the audit of our employee benefit plans and accounting consultations. The fees also include amounts for the services provided in connection with our securities offerings and accounting consultations and audits in connection with acquisitions.
(3)
Tax fees were professional services for federal and state tax compliance, tax advice and tax planning, including services to support merger and acquisition activity.
(4)
All other fees were for services other than the services reported above. These services included subscriptions to the Deloitte Accounting Research Tool and attendance at the Deloitte Power and Utilities Seminar.
The Audit and Risk Committee of the Board of Directors does not consider the provision of the services described above by Deloitte to be incompatible with the maintenance of Deloitte’s independence.
The Audit and Risk Committee has adopted a pre-approval policy for all audit and non-audit services pursuant to which it pre-approves all audit and non-audit services provided by the independent registered public accounting firm prior to the engagement with respect to such services. To the extent that we need an engagement for audit and/or non-audit services between Audit and Risk Committee meetings, the Audit and Risk Committee chairman is authorized by the Audit and Risk Committee to approve the required engagement on its behalf.
The Audit and Risk Committee, or the Audit and Finance Committee with respect to actions prior to the Merger, approved all of the services performed by Deloitte in 2016.


136

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
 
 
Report of Independent Registered Public Accounting Firm
 
 
Consolidated Statements of Financial Position as of December 31, 2016 and 2015
 
 
Consolidated Statements of Operations for the Years Ended December 31, 2016, 2015 and 2014
 
 
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2016, 2015 and 2014
 
 
Consolidated Statements of Changes in Stockholders’ Equity for the Years Ended December 31, 2016, 2015 and 2014
 
 
Consolidated Statements of Cash Flows for the Years Ended December 31, 2016, 2015 and 2014
 
 
Notes to Consolidated Financial Statements
 
(2)
Financial Statement Schedules
 
 
Schedule I — Condensed Financial Information of Registrant
 
 
All other schedules for which provision is made in Regulation S-X either (i) are not required under the related instructions or are inapplicable and, therefore, have been omitted, or (ii) the information required is included in the consolidated financial statements or the notes thereto that are a part hereof.
(b)
 
The exhibits included as part of this report are listed in the attached Exhibit Index, which is incorporated herein by reference.


137

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)
2016
 
2015
ASSETS
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
4

 
$
8

Accounts receivable from subsidiaries
16

 
38

Income tax receivable
17

 
—

Prepaid and other current assets
8

 
2

Total current assets
45

 
48

Other assets
 
 
 
Investment in subsidiaries
4,171

 
4,011

Deferred income taxes
208

 
21

Other
78

 
65

Total other assets
4,457

 
4,097

TOTAL ASSETS
$
4,502

 
$
4,145

LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
Current liabilities
 
 
 
Intercompany tax payable to subsidiaries
$
85

 
$
—

Accrued compensation
14

 
24

Accrued interest
33

 
35

Debt maturing within one year
195

 
395

Other
13

 
10

Total current liabilities
340

 
464

Accrued pension and postretirement liabilities
68

 
62

Other
1

 
1

Long-term debt (net of deferred financing fees and discount of $16 and $14, respectively)
2,192

 
1,909

STOCKHOLDERS’ EQUITY
 
 
 
Common stock, without par value, 235,000,000 shares authorized as of December 31, 2016, and 224,203,112 and 152,699,077 shares issued and outstanding at December 31, 2016 and 2015, respectively
892

 
829

Retained earnings
1,007

 
876

Accumulated other comprehensive income
2

 
4

Total stockholders’ equity
1,901

 
1,709

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
$
4,502

 
$
4,145

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


138

SCHEDULE I — Condensed Financial Information of Registrant
ITC HOLDINGS CORP.
CONDENSED STATEMENTS OF OPERATIONS (PARENT COMPANY ONLY)
 
Year Ended December 31,
(In millions)
2016
 
2015
 
2014
Other income
$
1

 
$
1

 
$
1

General and administrative expense
(122
)
 
(6
)
 
(7
)
Interest expense
(113
)
 
(106
)
 
(105
)
Loss on extinguishment of debt
—

 
—

 
(29
)
Other expense
—

 
—

 
(1
)
LOSS BEFORE INCOME TAXES
(234
)
 
(111
)
 
(141
)
INCOME TAX BENEFIT
(122
)
 
(45
)
 
(55
)
LOSS AFTER TAXES
(112
)
 
(66
)
 
(86
)
EQUITY IN SUBSIDIARIES’ NET EARNINGS
358

 
308

 
330

NET INCOME
$
246

 
$
242

 
$
244

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


139

SCHEDULE I — Condensed Financial Information of Registrant
ITC HOLDINGS CORP.
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (PARENT COMPANY ONLY)
 
Year Ended December 31,
(In millions)
2016
 
2015
 
2014
NET INCOME
$
246

 
$
242

 
$
244

OTHER COMPREHENSIVE LOSS
 
 
 
 
 
Derivative instruments (net of tax of $3, $1 and $2 for the years ended December 31, 2016, 2015 and 2014, respectively)
(2
)
 
(1
)
 
(2
)
TOTAL OTHER COMPREHENSIVE LOSS, NET OF TAX
(2
)
 
(1
)
 
(2
)
TOTAL COMPREHENSIVE INCOME
$
244

 
$
241

 
$
242

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




140

SCHEDULE I — Condensed Financial Information of Registrant
ITC HOLDINGS CORP.
CONDENSED STATEMENTS OF CASH FLOWS (PARENT COMPANY ONLY)
 
Year Ended December 31,
(In millions)
2016
 
2015
 
2014
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
 
 
Net income
$
246

 
$
242

 
244

Adjustments to reconcile net income to net cash (used in) provided by operating activities:
 
 
 
 
 
Equity in subsidiaries' earnings
(358
)
 
(308
)
 
(330
)
Dividends from subsidiaries
10

 
185

 
224

Deferred and other income taxes
(69
)
 
(116
)
 
(122
)
Net intercompany tax payments (to) from subsidiaries
(72
)
 
121

 
124

Expense for the accelerated vesting of share-based awards associated with the Merger
41

 
—

 
—

Loss on extinguishment of debt
—

 
—

 
29

Other
25

 
21

 
18

Changes in assets and liabilities, exclusive of changes shown separately:
 
 
 
 
 
Accounts receivable from subsidiaries
22

 
3

 
1

Income tax receivable
(17
)
 
—

 
—

Prepaid and other current assets
1

 
—

 
4

Intercompany tax payable to subsidiaries
85

 
—

 
—

Accrued Compensation
(10
)
 
1

 
2

Accrued taxes
(35
)
 
9

 
11

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

 
(12
)
 
(8
)
Other current liabilities
3

 
3

 
(9
)
Other non-current assets and liabilities, net
5

 
7

 
4

Net cash (used in) provided by operating activities
(123
)
 
156

 
192

CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
 
 
Equity contributions to subsidiaries
(87
)
 
(263
)
 
(349
)
Return of capital from subsidiaries
274

 
161

 
127

Other
(9
)
 
(11
)
 
(7
)
Net cash provided by (used in) investing activities
178

 
(113
)
 
(229
)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
 
 
Issuance of long-term debt, net of discount
399

 
—

 
399

Borrowings under revolving credit agreement
126

 
839

 
534

Borrowings under term loan credit agreement
—

 
—

 
60

Net issuance of commercial paper, net of discount
48

 
95

 
—

Retirement of long-term debt — including extinguishment of debt costs
(139
)
 
—

 
(249
)
Repayments of revolving credit agreement
(191
)
 
(755
)
 
(480
)
Repayments of term loan credit agreements
(161
)
 
—

 
(39
)
Dividends on common stock
(90
)
 
(108
)
 
(96
)
Dividends to ITC Investment Holdings Inc.
(33
)
 
—

 
—

Issuance of common stock
13

 
14

 
21

Repurchase and retirement of common stock
(9
)
 
(137
)
 
(134
)
Settlement of share-based compensation awards associated with the Merger — including cost of accelerated share-based awards
(137
)
 
—

 
—

Contribution from ITC Investment Holdings Inc. for the settlement of share-based awards associated with the Merger
137

 
—

 
—

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

 
12

 
8

Advance for forward contract of accelerated share repurchase program
—

 
—

 
(20
)
Return of unused advance for forward contract of accelerated share repurchase program
—

 
—

 
20

Other
(22
)
 
(1
)
 
(8
)
Net cash (used in) provided by financing activities
(59
)
 
(41
)
 
16

NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS
(4
)
 
2

 
(21
)
CASH AND CASH EQUIVALENTS — Beginning of period
8

 
6

 
27

CASH AND CASH EQUIVALENTS — End of period
$
4

 
$
8

 
$
6

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


141

SCHEDULE I — Condensed Financial Information of Registrant
ITC HOLDINGS CORP.
NOTES TO CONDENSED FINANCIAL STATEMENTS (PARENT COMPANY ONLY)
1.     GENERAL
For ITC Holdings Corp.’s (“ITC Holdings,” “we,” “our” and “us”) presentation (Parent Company only), the investment in subsidiaries is accounted for using the equity method. The condensed parent company financial statements and notes should be read in conjunction with the consolidated financial statements and notes of ITC Holdings appearing in this Annual Report on Form 10-K.
As a holding company with no business operations, ITC Holdings’ assets consist primarily of investments in our subsidiaries. ITC Holdings’ material cash inflows are only from dividends and other payments received from our subsidiaries, the proceeds raised from the sale of debt securities, issuances under our commercial paper program and borrowings under our revolving credit agreement. ITC Holdings may not be able to access cash generated by our subsidiaries in order to fulfill cash commitments. The ability of our subsidiaries to make dividend and other payments to us is subject to the availability of funds after taking into account their respective funding requirements, the terms of their respective indebtedness, the regulations of the FERC under the FPA and applicable state laws. In addition, there are practical limitations on using the net assets of each of our Regulated Operating Subsidiaries as of December 31, 2016 for dividends based on management's intent to maintain the FERC-approved capital structure targeting 60% equity and 40% debt for each of our Regulated Operating Subsidiaries. These net assets are included in Schedule I as the line-item “Investments in subsidiaries.” Each of our subsidiaries, however, is legally distinct from us and has no obligation, contingent or otherwise, to make funds available to us.
Supplementary Cash Flows Information
 
Year Ended December 31,
(In millions)
2016
 
2015
 
2014
Supplementary cash flows information:
 
 
 
 
 
Interest paid (net of interest capitalized)
$
112

 
$
104

 
$
106

Income taxes paid (a)
23

 
56

 
45

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

 
1

 
6

____________________________
(a)
Amount for the year ended December 31, 2016 does not include the income tax refund of $128 million received from the Internal Revenue Service in August 2016, which resulted from the election of bonus depreciation as described in Note 5 to the consolidated financial statements.
2.     DEBT
As of December 31, 2016, the maturities of our debt outstanding were as follows:
(In millions)
 
2017
$
195

2018
385

2019
73

2020
200

2021
—

2022 and thereafter
1,550

Total
$
2,403

Refer to Note 9 to the consolidated financial statements for a description of the ITC Holdings Senior Notes, the ITC Holdings Revolving Credit Agreements, the ITC Holdings Commercial Paper Program and related items.
Based on the borrowing rates obtained from third party lending institutions currently available for bank loans with similar terms and average maturities from active markets, the fair value of the ITC Holdings Senior Notes was $2,297 million and $2,059 million at December 31, 2016 and 2015, respectively. The total book value of the ITC


142

Holdings Senior Notes, net of discount and deferred financing fees, was $2,169 million and $1,921 million at December 31, 2016 and 2015, respectively. At December 31, 2016 and 2015, we had a total of $73 million and $299 million, respectively, outstanding under our revolving and term loan credit agreements, which are variable rate loans. The fair value of these loans approximates book value based on the borrowing rates currently available for variable rate loans obtained from third party lending institutions. These fair values represent Level 2 under the three-tier hierarchy described in Note 12 to the consolidated financial statements. At December 31, 2016 and 2015, ITC Holdings had $145 million and $95 million, respectively, of commercial paper issued and outstanding under the commercial paper program. Due to the short-term nature of these financial instruments, the carrying value approximates fair value.
Covenants
Our debt instruments contain numerous financial and operating covenants that place significant restrictions on certain transactions, such as incurring additional indebtedness, engaging in sale and lease-back transactions, creating liens or other encumbrances, entering into mergers, consolidations, liquidations or dissolutions and paying dividends. In addition, the covenants require us to meet certain financial ratios, such as maintaining certain debt to capitalization ratios. At December 31, 2016, we were not in violation of any debt covenant.
3.     RELATED-PARTY TRANSACTIONS
Our related-party transactions during 2016, 2015 and 2014 were as follows:
 
Year Ended December 31,
(In millions)
2016
 
2015
 
2014
Equity contributions to subsidiaries
$
87

 
$
263

 
$
349

Dividends from subsidiaries (a)
10

 
185

 
224

Return of capital from subsidiaries (a)
274

 
161

 
127

 
 
 
 
 
 
Net income tax payments (to) from: (b)
 
 
 
 
 
ITCTransmission
$
(28
)
 
$
36

 
$
38

MTH
(14
)
 
39

 
41

ITC Midwest
(34
)
 
31

 
34

ITC Great Plains
4

 
15

 
11

____________________________
(a)
Includes ITCTransmission, MTH, ITC Midwest and other subsidiaries.
(b)
The net income tax payments were pursuant to intercompany tax sharing arrangements, and the total of these tax payments is presented as a net cash outflow or inflow from operating activities in the condensed parent company statements of cash flows. Other reconciling items between the parent company and the consolidated tax liabilities are presented as deferred and other income taxes in the adjustments to reconcile net income to net cash provided by operating activities.


143

ITEM 16.     FORM 10-K SUMMARY.
Not applicable.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized in the City of Novi, State of Michigan, on February 16, 2017.
ITC HOLDINGS CORP.
 
 
By:  
/s/ LINDA H. BLAIR
 
 
Linda H. Blair
 
 
President and Chief Executive Officer
 
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant and in the capacities and on the dates indicated:
Signature
Title
Date
/s/ LINDA H. BLAIR
President and Chief
February 16, 2017
Linda H. Blair
Executive Officer (principal executive officer)
 
 
 
 
/s/ GRETCHEN L. HOLLOWAY
Vice President, Chief Financial
February 16, 2017
Gretchen L. Holloway
Officer and Treasurer (principal financial
 
 
and accounting officer)
 
 
 
 
/s/ JOSEPH L. WELCH
Director and Chairman
February 16, 2017
Joseph L. Welch
 
 
 
 
 
/s/ ROBERT A. ELLIOTT
Director
February 16, 2017
Robert A. Elliott
 
 
 
 
 
/s/ ALBERT ERNST
Director
February 16, 2017
Albert Ernst
 
 
 
 
 
/s/ RHYS D. EVENDEN
Director
February 16, 2017
Rhys D. Evenden
 
 
 
 
 
/s/ JAMES P. LAURITO
Director
February 16, 2017
James P. Laurito
 
 
 
 
 
/s/ BARRY V. PERRY
Director
February 16, 2017
Barry V. Perry
 
 
 
 
 
/s/ SANDRA E. PIERCE
Director
February 16, 2017
Sandra E. Pierce
 
 
 
 
 
/s/ KEVIN L. PRUST
Director
February 16, 2017
Kevin L. Prust
 
 
 
 
 
/s/ THOMAS G. STEPHENS
Director
February 16, 2017
Thomas G. Stephens
 
 


144

EXHIBITS
The following exhibits are filed as part of this report or filed previously and incorporated by reference to the filing indicated. Our SEC file number is 001-32576.
Exhibit No.
 
Description of Exhibit
 
 
 
2.1

 
Agreement and Plan of Merger, dated as of February 9, 2016, among FortisUS Inc., Element Acquisition Sub Inc., Fortis Inc., and ITC Holdings Corp. (filed with Registrant’s Form 8-K filed on February 11, 2016)
 
 
 
3.1

 
Restated Articles of Incorporation of ITC Holdings Corp. (filed with Registrant’s Form 10-Q for the quarter ended September 30, 2016)
 
 
 
3.2

 
Sixth Amended and Restated Bylaws of ITC Holdings Corp (filed with Registrant’s Form 8-K filed on October 12, 2016)
 
 
 
4.3

 
Indenture, dated as of July 16, 2003, between the Registrant and BNY Midwest Trust Company, as trustee (filed with Registrant’s Registration Statement on Form S-1, as amended, Reg. No. 333-123657)
 
 
 
4.5

 
First Mortgage and Deed of Trust, dated as of July 15, 2003, between International Transmission Company and BNY Midwest Trust Company, as trustee (filed with Registrant’s Registration Statement on Form S-1, as amended, Reg. No. 333-123657)
 
 
 
4.6

 
First Supplemental Indenture, dated as of July 15, 2003, supplementing the First Mortgage and Deed of Trust dated as of July 15, 2003, between International Transmission Company and BNY Midwest Trust Company, as trustee (filed with Registrant’s Registration Statement on Form S-1, as amended, Reg. No. 333-123657)
 
 
 
4.7

 
Second Supplemental Indenture, dated as of July 15, 2003, supplementing the First Mortgage and Deed of Trust dated as of July 15, 2003, between International Transmission Company and BNY Midwest Trust Company, as trustee (filed with Registrant’s Registration Statement on Form S-1, as amended, Reg. No. 333-123657)
 
 
 
4.8

 
Amendment to Second Supplemental Indenture, dated as of January 19, 2005, between International Transmission Company and BNY Midwest Trust Company, as trustee (filed with Registrant’s Registration Statement on Form S-1, as amended, Reg. No. 333-123657)
 
 
 
4.9

 
Second Amendment to Second Supplemental Indenture, dated as of March 24, 2006, between International Transmission Company and The Bank of New York Trust Company, N.A. (as successor to BNY Midwest Trust Company), as trustee (filed with Registrant’s Form 8-K filed on March 30, 2006)
 
 
 
4.10

 
Third Supplemental Indenture, dated as of March 28, 2006, supplementing the First Mortgage and Deed of Trust dated as of July 15, 2003, between International Transmission Company and BNY Midwest Trust Company, as trustee (filed with Registrant’s Form 8-K filed on March 30, 2006)
 
 
 
4.12

 
Second Supplemental Indenture, dated as of October 10, 2006, supplemental to the Indenture dated as of July 16, 2003, between the Registrant and The Bank of New York Trust Company, N.A., (as successor to BNY Midwest Trust Company, as trustee) (filed with Registrant’s Form 8-K filed on October 10, 2006)
 
 
 
4.14

 
First Mortgage Indenture between Michigan Electric Transmission Company, LLC and JPMorgan Chase Bank, dated as of December 10, 2003 (filed with Registrant’s Form 10-Q for the quarter ended September 30, 2006)
 
 
 
4.17

 
ITC Holdings Corp. Note Purchase Agreement, dated as of September 20, 2007 (filed with Registrant’s Form 10-Q for the quarter ended September 30, 2007)
 
 
 
4.18

 
Third Supplemental Indenture, dated as of January 24, 2008, supplemental to the Indenture dated as of July 16, 2003, between the Registrant and The Bank of New York Trust Company, N.A. (as successor to BNY Midwest Trust Company), as trustee (filed with Registrant’s Form 8-K filed on January 25, 2008)
 
 
 
4.19

 
First Mortgage and Deed of Trust, dated as of January 14, 2008, between ITC Midwest LLC and The Bank of New York Trust Company, N.A., as trustee (filed with Registrant’s Form8-K filed on February 1, 2008)
 
 
 
4.20

 
First Supplemental Indenture, dated as of January 14, 2008, supplemental to the First Mortgage Indenture between ITC Midwest LLC and The Bank of New York Trust Company, N.A., as trustee, First Mortgage and Deed of Trust, dated as of January 14, 2008 (filed with Registrant’s Form 8-K filed on February 1, 2008)
 
 
 
4.21

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


145

Exhibit No.
 
Description of Exhibit

4.23

 
Second Supplemental Indenture, dated as of December 15, 2008, between ITC Midwest LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Trust Company, N.A.), as trustee, to the First Mortgage and Deed of Trust, dated as of January 14, 2008 (filed with Registrant’s Form 8-K filed on December 23, 2008)
 
 
 
4.24

 
Third Supplemental Indenture, dated as of November 25, 2008, between METC and The Bank of New York Mellon Trust Company, N.A. (as successor to JPMorgan Chase Bank, N.A.), as trustee, to the First Mortgage Indenture between Michigan Electric Transmission Company, LLC and JPMorgan Chase Bank, dated as of December 10, 2003 (filed with Registrant’s Form 8-K filed on December 23, 2008)
 
 
 
4.25

 
Fourth Supplemental Indenture, dated as of December 11, 2009, between ITC Holdings Corp. and The Bank of New York Mellon Trust Company, N.A. (f.k.a. The Bank of New York Trust Company, N.A., as successor to BNY Midwest Trust Company), as trustee (filed with Registrant’s Form 8-K filed on December 14, 2009)
 
 
 
4.26

 
Fourth Supplemental Indenture, dated as of December 10, 2009, between ITC Midwest LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Trust Company, N.A.), as trustee (filed with Registrant’s Form 8-K filed on December 17, 2009)
 
 
 
4.27

 
Fifth Supplemental Indenture, dated as of April 20, 2010, between Michigan Electric Transmission Company, LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to JPMorgan Chase Bank), as trustee (filed with Registrant’s Form 8-K filed on May 10, 2010)
 
 
 
4.28

 
Third Supplemental Indenture, dated as of December 15, 2008, between ITC Midwest LLC and The Bank of New York Mellon Trust Company, N.A. (The Bank of New York Trust Company, N.A.), as trustee (filed with Registrant’s Form 10-Q for the quarter ended June 30, 2011)
 
 
 
4.29

 
Fifth Supplemental Indenture, dated as of July 15, 2011, between ITC Midwest LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Trust Company, N.A.), as trustee (filed with Registrant’s Form 10-Q for the quarter ended June 30, 2011)
 
 
 
4.30

 
Sixth Supplemental Indenture, dated as of November 29, 2011, between ITC Midwest LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Trust Company, N.A.), as trustee (filed with Registrant’s Form 8-K filed on December 1, 2011)
 
 
 
4.31

 
Sixth Supplemental Indenture, dated as of October 5, 2012, between Michigan Electric Transmission Company, LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to JPMorgan Chase Bank), as trustee (filed with Registrant's Form 8-K filed on October 29, 2012)
 
 
 
4.32

 
Seventh Supplemental Indenture, dated as of March 18, 2013, between ITC Midwest LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Trust Company, N.A.), as trustee (filed with Registrant’s Form 8-K filed on April 8, 2013)
 
 
 
4.33

 
Indenture, dated as of April 18, 2013, between ITC Holdings Corp. and Wells Fargo Bank, National Association, as trustee (including form of note) (filed with Registrant's Form S-3 on April 18, 2013)
 
 
 
4.34

 
First Supplemental Indenture, dated as of July 3, 2013, between ITC Holdings Corp and Wells Fargo Bank, National Association, as trustee (including forms of notes) (filed with Registrant's Form 8-K on July 3, 2013)
 
 
 
4.35

 
Fifth Supplemental Indenture, dated as of August 7, 2013, between International Transmission Company and The Bank of New York Mellon Trust Company, N.A. (as successor to BNY Midwest Trust Company), as trustee (including form of bonds) (filed with Registrant’s Form 8-K on August 16, 2013)
 
 
 
4.36

 
Fifth Supplemental Indenture, dated May 16, 2014, between ITC Holdings Corp. and The Bank of New York Mellon Trust Company, N.A. (f.k.a. The Bank of New York Trust Company, N.A., as successor to BNY Midwest Trust Company), as Trustee (filed with Registrant’s Form 8-K on May 16, 2014)
 
 
 
4.38

 
Second Supplemental Indenture, dated as of June 4, 2014 between ITC Holdings Corp. and Wells Fargo Bank, National Association, as trustee, together with form of 3.65% Senior Note due 2024 (filed with Registrant’s Form 8-K on June 4, 2014)
 
 
 
4.39

 
Sixth Supplemental Indenture, dated as of May 23, 2014, between International Transmission Company and The Bank of New York Mellon Trust Company, N.A. (as successor to BNY Midwest Trust Company), as trustee (filed with Registrant’s Form 8-K on June 10, 2014)
 
 
 
4.40

 
First Mortgage and Deed of Trust, dated as of November 12, 2014, between ITC Great Plains, LLC and Wells Fargo Bank, National Association, as trustee (filed with Registrant’s Form 8-K on November 26, 2014)
 
 
 
4.41

 
First Supplemental Indenture, dated as of November 12, 2014, between ITC Great Plains, LLC and Wells Fargo Bank, National Association, as trustee (filed with Registrant’s Form 8-K on November 26, 2014)
 
 
 


146

Exhibit No.
 
Description of Exhibit

4.42

 
Seventh Supplemental Indenture, dated as of December 5, 2014, between Michigan Electric Transmission Company, LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to JPMorgan Chase Bank), as trustee (filed with Registrant’s Form 8-K on December 22, 2014)
 
 
 
4.43

 
Eighth Supplemental Indenture, dated as of March 18, 2015, between ITC Midwest LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Trust Company, N.A.), as trustee (filed with Registrant’s Form 8-K filed on April 8, 2015)
 
 
 
4.44

 
Eighth Supplemental Indenture, dated as of March 31, 2016, between Michigan Electric Transmission Company, LLC and Bank of New York Mellon Trust Company, N.A. (as successor to JPMorgan Chase Bank), as trustee (filed with Registrant’s Form 8-K filed on April 26, 2016)
 
 
 
4.45

 
Third Supplemental Indenture, dated as of July 5, 2016, between the Company and Wells Fargo Bank, National Association, as trustee, together with form of 3.25% Note due 2026 (filed with Registrant’s Form 8-K filed on July 5, 2016)
 
 
 
*10.27

 
Deferred Compensation Plan (filed with Registrant’s Registration Statement on Form S-1, as amended, Reg. No. 333-123657)
 
 
 
*10.45

 
Form of Restricted Stock Award Agreement for Employees under the Registrant’s 2006 Long Term Incentive Plan (filed with Registrant’s Form 8-K filed on August 18, 2006)
 
 
 
*10.46

 
Form of Stock Option Agreement for Employees under the Registrant’s 2006 Long Term Incentive Plan (filed with Registrant’s Form 8-K filed on August 18, 2006)
 
 
 
10.51

 
Form of Amended and Restated Easement Agreement between Consumers Energy Company and Michigan Electric Transmission Company (filed with Registrant’s Form 10-Q for the quarter ended September 30, 2006)
 
 
 
*10.64

 
Form of Amended and Restated Executive Group Special Bonus Plan of the Registrant, dated November 12, 2007 (filed with Registrant’s 2007 Form 10-K)
 
 
 
*10.75

 
Form of Amendment to Stock Option Agreement under 2006 LTIP (August 2008) (filed with Registrant’s Form 8-K filed on August 19, 2008)
 
 
 
*10.76

 
Form of Amendment to Restricted Stock Agreement under 2006 LTIP) (August 2008) (filed with Registrant’s Form 8-K filed on August 19, 2008)
 
 
 
*10.77

 
Form of Stock Option Agreement under 2006 LTIP (August 2008) (filed with Registrant’s Form 8-K filed on August 19, 2008)
 
 
 
*10.78

 
Form of Restricted Stock Award Agreement under 2006 LTIP (August 2008) (filed with Registrant’s Form 8-K filed on August 19, 2008)
 
 
 
*10.80

 
Management Supplemental Benefit Plan (filed with Registrant’s 2008 Form 10-K)
 
 
 
*10.81

 
Executive Supplemental Retirement Plan (filed with Registrant’s 2008 Form 10-K)
 
 
 
*10.97

 
Second Amended and Restated 2006 Long Term Incentive Plan effective May 26, 2011 (filed with Registrant’s Form 8-K on June 1, 2011)
 
 
 
10.104

 
Form of Stock Option Agreement for Executive Officers under Second Amended and Restated 2006 LTIP (May 2012) (filed with Registrant’s Form 10-Q for the quarter ended June 30, 2012)
 
 
 
10.105

 
Form of Restricted Stock Award Agreement for Executive Officers under Second Amended and Restated 2006 LTIP (May 2012) (filed with Registrant’s Form 10-Q for the quarter ended June 30, 2012)
 
 
 
*10.108

 
Employment Agreement between ITC Holdings Corp. and Joseph L. Welch, effective as of December 21, 2012 (filed with Registrant's Form 8-K on December 26, 2012)
 
 
 
*10.109

 
Employment Agreement between ITC Holdings Corp. and Linda H. Blair, effective as of December 21, 2012 (filed with Registrant's Form 8-K on December 26, 2012)
 
 
 
*10.110

 
Employment Agreement between ITC Holdings Corp. and Jon E. Jipping, effective as of December 21, 2012 (filed with Registrant's Form 8-K on December 26, 2012)
 
 
 
*10.111

 
Employment Agreement between ITC Holdings Corp. and Daniel J. Oginsky, effective as of December 21, 2012 (filed with Registrant's Form 8-K on December 26, 2012)
 
 
 
*10.112

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


147

Exhibit No.
 
Description of Exhibit

*10.120

 
First Amendment to Executive Supplemental Retirement Plan, dated as of May 16, 2013 (filed with Registrant’s Form 10-Q for the quarter ended June 30, 2013)
 
 
 
*10.122

 
Recoupment Policy and Related Consent, effective January 1, 2014 (filed with Registrant's Form 8-K on December 2, 2013)
 
 
 
10.126

 
ITC Holdings Revolving Credit Agreement, dated as of March 28, 2014, among ITC Holdings Corp., the various financial institutions and other persons from time to time parties thereto as lenders, JPMorgan Chase Bank, N.A., as administrative agent, J.P. Morgan Securities LLC, Barclays Bank PLC and Wells Fargo Securities, LLC, as joint lead arrangers and joint bookrunners, and Barclays Bank PLC and Wells Fargo Bank, National Association, as syndication agents (filed with Registrant’s Form 8-K on March 28, 2014)
 
 
 
10.127

 
ITCTransmission Revolving Credit Agreement, dated as of March 28, 2014, among International Transmission Company, the various financial institutions and other persons from time to time parties thereto as lenders, JPMorgan Chase Bank, N.A., as administrative agent, J.P. Morgan Securities LLC, Barclays Bank PLC and Wells Fargo Securities, LLC, as joint lead arrangers and joint bookrunners, and Barclays Bank PLC and Wells Fargo Bank, National Association, as syndication agents (filed with Registrant’s Form 8-K on March 28, 2014)
 
 
 
10.128

 
METC Revolving Credit Agreement, dated as of March 28, 2014, among Michigan Electric Transmission Company, LLC, the various financial institutions and other persons from time to time parties thereto as lenders, JPMorgan Chase Bank, N.A., as administrative agent, J.P. Morgan Securities LLC, Barclays Bank PLC and Wells Fargo Securities, LLC, as joint lead arrangers and joint bookrunners, and Barclays Bank PLC and Wells Fargo Bank, National Association, as syndication agents (filed with Registrant’s Form 8-K on March 28, 2014)
 
 
 
10.129

 
ITC Midwest Revolving Credit Agreement, dated as of March 28, 2014, among ITC Midwest LLC, the various financial institutions and other persons from time to time parties thereto as lenders, JPMorgan Chase Bank, N.A., as administrative agent, J.P. Morgan Securities LLC, Barclays Bank PLC and Wells Fargo Securities, LLC, as joint lead arrangers and joint bookrunners, and Barclays Bank PLC and Wells Fargo Bank, National Association, as syndication agents (filed with Registrant’s Form 8-K on March 28, 2014)
 
 
 
10.130

 
ITC Great Plains Revolving Credit Agreement, dated as of March 28, 2014, among ITC Great Plains, LLC, the various financial institutions and other persons from time to time parties thereto as lenders, JPMorgan Chase Bank, N.A., as administrative agent, J.P. Morgan Securities LLC, Barclays Bank PLC and Wells Fargo Securities, LLC, as joint lead arrangers and joint bookrunners, and Barclays Bank PLC and Wells Fargo Bank, National Association, as syndication agents (filed with Registrant’s Form 8-K on March 28, 2014)
 
 
 
*10.133

 
Form of Notice and Amendment to Stock Option Agreement for Executive Officers under Amended and Restated 2003 Stock Purchase and Option Plan, as amended (May 2014) (filed with Registrant’s Form 10-Q for quarter ended June 30, 2014)
 
 
 
*10.134

 
Form of Notice and Amendment to Stock Option Agreement for Executive Officers under Second Amended and Restated 2006 LTIP (May 2014) (filed with Registrant’s Form 10-Q for quarter ended June 30, 2014)
 
 
 
*10.135

 
Form of Stock Option Agreement for Executive Officers under Second Amended and Restated 2006 LTIP (May 2014) (filed with Registrant’s Form 10-Q for quarter ended June 30, 2014)
 
 
 
*10.136

 
Form of Stock Award Agreement for Executive Officers under Second Amended and Restated 2006 LTIP (May 2014) (filed with Registrant’s Form 10-Q for quarter ended June 30, 2014)
 
 
 
*10.138

 
Employment Agreement between ITC Holdings Corp. and Rejji P. Hayes, effective as of October 27, 2014 (filed with Registrant’s Form 8-K on October 29, 2014)
 
 
 
*10.141

 
Form of Restricted Stock Award Agreement (5 year vesting) (February 2015) (filed with Registrant’s Form 10-Q for the quarter ended March 30, 2015)
 
 
 
*10.143

 
ITC Holdings Corp. 2015 Employee Stock Purchase Plan (filed with Registrant’s Form 10-Q for the quarter ended June 30, 2015)
 
 
 
*10.144

 
ITC Holdings Corp. 2015 Long Term Incentive Plan (filed with Registrant’s Form 10-Q for the quarter ended June 30, 2015)
 
 
 
*10.145

 
Form of Stock Option Grant Agreement under Second Amended and Restated 2006 LTIP (May 2015) (filed with Registrant’s Form 10-Q for the quarter ended June 30, 2015)
 
 
 
*10.146

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


148

Exhibit No.
 
Description of Exhibit

*10.147

 
Form of Performance Share Award Agreement under Second Amended and Restated 2006 LTIP (May 2015) (filed with Registrant’s Form 10-Q for the quarter ended June 30, 2015)
 
 
 
*10.148

 
Form of Amendment to 2014 Stock Option Grant Agreement (May 2015) (filed with Registrant’s Form 10-Q for the quarter ended June 30, 2015)
 
 
 
*10.149

 
Form of Amendment to 2014 Restricted Stock Grant Agreement (May 2015) (filed with Registrant’s Form 10-Q for the quarter ended June 30, 2015)
 
 
 
*10.150

 
Employment Agreement between ITC Holdings Corp. and Christine Mason Soneral, effective as of February 3, 2015 (filed with Registrant’s Form 10-Q for the quarter ended June 30, 2015)
 
 
 
10.152

 
METC 2015 Term Loan Credit Agreement dated as of December 8, 2015, among Michigan Electric Transmission Company, LLC, the various financial institutions and other persons from time to time parties thereto as lenders, and Barclays Bank PLC, as administrative agent for the Lenders and the other agents party thereto. (filed with Registrant’s Form 8-K on December 10, 2015)
 
 
 
*10.155

 
Letter Agreement, dated as of February 8, 2016, between ITC Holdings Corp. and Joseph L. Welch (filed with Registrant’s Form 8-K filed on February 11, 2016)
 
 
 
*10.156

 
Summary of 2016 Incentive Compensation Plan (filed with Registrant’s Form 10-Q for the quarter ended March 31, 2016)
 
 
 
10.157

 
Amendment No. 1, dated as of April 7, 2016, to the Revolving Credit Agreement, dated as of March 28, 2014, by and among ITC Holdings, as the borrower, various financial institutions and other persons from time to time parties thereto as lenders, JPMorgan Chase Bank, N.A., as administrative agent, J.P. Morgan Securities LLC, Barclays Bank PLC and Wells Fargo Securities, LLC, as joint lead arrangers and joint bookrunners, and Barclays Bank PLC and Wells Fargo Bank, National Association, as syndication agents (filed with Registrant’s Form 8-K filed on April 11, 2016)
 
 
 
10.158

 
Amendment No. 1, dated as of April 7, 2016, to the Revolving Credit Agreement, dated as of March 28, 2014, by and among ITCTransmission, as the borrower, various financial institutions and other persons from time to time parties thereto as lenders, JPMorgan Chase Bank, N.A., as administrative agent, J.P. Morgan Securities LLC, Barclays Bank PLC and Wells Fargo Securities, LLC, as joint lead arrangers and joint bookrunners, and Barclays Bank PLC and Wells Fargo Bank, National Association, as syndication agents (filed with Registrant’s Form 8-K filed on April 11, 2016)
 
 
 
10.159

 
Amendment No. 1, dated as of April 7, 2016, to the Revolving Credit Agreement, dated as of March 28, 2014, by and among METC, as the borrower, various financial institutions and other persons from time to time parties thereto as lenders, JPMorgan Chase Bank, N.A., as administrative agent, J.P. Morgan Securities LLC, Barclays Bank PLC and Wells Fargo Securities, LLC, as joint lead arrangers and joint bookrunners, and Barclays Bank PLC and Wells Fargo Bank, National Association, as syndication agents (filed with Registrant’s Form 8-K filed on April 11, 2016)
 
 
 
10.160

 
Amendment No. 1, dated as of April 7, 2016, to the Revolving Credit Agreement, dated as of March 28, 2014, by and among ITC Midwest, as the borrower, various financial institutions and other persons from time to time parties thereto as lenders, JPMorgan Chase Bank, N.A., as administrative agent, J.P. Morgan Securities LLC, Barclays Bank PLC and Wells Fargo Securities, LLC, as joint lead arrangers and joint bookrunners, and Barclays Bank PLC and Wells Fargo Bank, National Association, as syndication agents (filed with Registrant’s Form 8-K filed on April 11, 2016)
 
 
 
10.161

 
Amendment No. 1, dated as of April 7, 2016, to the Revolving Credit Agreement, dated as of March 28, 2014, by and among ITC Great Plains, as the borrower, various financial institutions and other persons from time to time parties thereto as lenders, JPMorgan Chase Bank, N.A., as administrative agent, J.P. Morgan Securities LLC, Barclays Bank PLC and Wells Fargo Securities, LLC, as joint lead arrangers and joint bookrunners, and Barclays Bank PLC and Wells Fargo Bank, National Association, as syndication agents (filed with Registrant’s Form 8-K filed on April 11, 2016)
 
 
 
*10.162

 
Form of Restricted Stock Award Agreement for Executive Officers under 2015 Long Term Incentive Plan (May 2016) (filed with Registrant’s Form 10-Q for the quarter ended June 30, 2016)
 
 
 
*10.163

 
Retention Award Letter, dated May 23, 2016, between ITC Holdings Corp. and Linda H. Blair (filed with Registrant’s Form 10-Q for the quarter ended June 30, 2016)
 
 
 
*10.164

 
Retention Award Letter, dated May 23, 2016, between ITC Holdings Corp. and Rejji P. Hayes (filed with Registrant’s Form 10-Q for the quarter ended June 30, 2016)
 
 
 
*10.165

 
Retention Award Letter, dated May 23, 2016, between ITC Holdings Corp. and Jon E. Jipping (filed with Registrant’s Form 10-Q for the quarter ended June 30, 2016)
 
 
 
*10.166

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


149

Exhibit No.
 
Description of Exhibit

*10.167

 
Letter Agreement, dated as of October 14, 2016, between ITC Holdings Corp. and Joseph L. Welch (filed with Registrant’s Form 8-K filed on October 12, 2016)
 
 
 
*10.168

 
Letter Agreement, dated as of October 14, 2016, between ITC Holdings Corp. and Linda H. Blair (filed with Registrant’s Form 8-K filed on October 12, 2016)
 
 
 
*10.169

 
Amended Employment Agreement, dated as of October 12, 2016, between ITC Holdings Corp. and Rejji P. Hayes (filed with Registrant’s Form 8-K filed on October 12, 2016)
 
 
 
*10.171

 
Amendment to Management Supplemental Benefit Plan, effective as of October 14, 2016
 
 
 
*10.172

 
Employment Agreement between ITC Holdings Corp. and Gretchen L. Holloway, effective as of February 3, 2015.
 
 
 
*10.173

 
Amended Employment Agreement, dated as of October 12, 2016 between ITC Holdings Corp. and Christine Mason Soneral
 
 
 
*10.174

 
Retention Award Letter, dated May 19, 2016 between ITC Holdings Corp. and Christine Mason Soneral
 
 
 
*10.175

 
Retention Award Letter, dated March 16, 2016 between ITC Holdings Corp. and Gretchen L. Holloway
 
 
 
12.1

 
Ratio of Earnings to Fixed Charges for ITC Holdings Corp.
 
 
 
21

 
List of Subsidiaries
 
 
 
31.1

 
Certification of Chief Executive Officer pursuant to Rule 13a-14 of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
 
 
31.2

 
Certification of Chief Financial Officer pursuant to Rule 13a-14 of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
 
 
32

 
Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
 
 
101.INS

 
XBRL Instance Document
 
 
 
101.SCH

 
XBRL Taxonomy Extension Schema
 
 
 
101.CAL

 
XBRL Taxonomy Extension Calculation Linkbase
 
 
 
101.DEF

 
XBRL Taxonomy Extension Definition Database
 
 
 
101.LAB

 
XBRL Taxonomy Extension Label Linkbase
 
 
 
101.PRE

 
XBRL Taxonomy Extension Presentation Linkbase
____________________________
*
 
Management contract or compensatory plan or arrangement.


150