Company Quick10K Filing
ITC Holdings
Closing Price ($) Shares Out (MM) Market Cap ($MM)
$0.00 224 $10,383
10-K 2020-02-13 Annual: 2019-12-31
10-Q 2019-11-01 Quarter: 2019-09-30
10-Q 2019-08-02 Quarter: 2019-06-30
10-Q 2019-05-01 Quarter: 2019-03-31
10-K 2019-02-15 Annual: 2018-12-31
10-Q 2018-11-02 Quarter: 2018-09-30
10-Q 2018-07-31 Quarter: 2018-06-30
10-Q 2018-05-01 Quarter: 2018-03-31
10-K 2018-02-15 Annual: 2017-12-31
10-Q 2017-11-03 Quarter: 2017-09-30
10-Q 2017-07-28 Quarter: 2017-06-30
10-Q 2017-05-02 Quarter: 2017-03-31
10-K 2017-02-16 Annual: 2016-12-31
10-Q 2016-11-04 Quarter: 2016-09-30
10-Q 2016-07-28 Quarter: 2016-06-30
10-Q 2016-04-28 Quarter: 2016-03-31
10-K 2016-02-25 Annual: 2015-12-31
10-Q 2015-11-05 Quarter: 2015-09-30
10-Q 2015-07-30 Quarter: 2015-06-30
10-Q 2015-04-30 Quarter: 2015-03-31
10-K 2015-02-26 Annual: 2014-12-31
10-Q 2014-10-30 Quarter: 2014-09-30
10-Q 2014-08-06 Quarter: 2014-06-30
10-Q 2014-05-01 Quarter: 2014-03-31
10-K 2014-02-27 Annual: 2013-12-31
10-Q 2013-10-31 Quarter: 2013-09-30
10-Q 2013-07-25 Quarter: 2013-06-30
10-Q 2013-04-24 Quarter: 2013-03-31
10-K 2013-03-01 Annual: 2012-12-31
10-Q 2012-08-01 Quarter: 2012-06-30
10-Q 2012-04-25 Quarter: 2012-03-31
10-K 2012-02-22 Annual: 2011-12-31
10-Q 2011-10-27 Quarter: 2011-09-30
10-Q 2011-07-29 Quarter: 2011-06-30
10-Q 2011-04-28 Quarter: 2011-03-31
10-K 2011-02-23 Annual: 2010-12-31
10-Q 2010-10-28 Quarter: 2010-09-30
10-Q 2010-07-30 Quarter: 2010-06-30
10-Q 2010-04-29 Quarter: 2010-03-31
10-K 2010-02-25 Annual: 2009-12-31
8-K 2020-02-11 Officers
8-K 2020-02-04 Officers, Shareholder Vote
8-K 2020-01-23 Enter Agreement, Off-BS Arrangement, Exhibits
8-K 2020-01-10 Enter Agreement, Off-BS Arrangement, Exhibits
8-K 2019-11-14 Officers
8-K 2019-08-28 Enter Agreement, Off-BS Arrangement, Exhibits
8-K 2019-07-10 Enter Agreement, Off-BS Arrangement, Officers, Shareholder Vote, Exhibits
8-K 2019-06-14 Enter Agreement, Off-BS Arrangement, Officers, Exhibits
8-K 2019-05-14 Other Events
8-K 2019-02-20 Officers, Exhibits
8-K 2019-02-13 Shareholder Vote
8-K 2019-01-15 Enter Agreement, Off-BS Arrangement, Exhibits
8-K 2018-11-15 Officers
8-K 2018-11-01 Enter Agreement, Off-BS Arrangement, Exhibits
8-K 2018-04-04 Leave Agreement
8-K 2018-03-29 Enter Agreement, Off-BS Arrangement, Exhibits
8-K 2018-02-27 Officers, Shareholder Vote
ITC 2019-12-31
Part I
Item 1. Business.
Item 1A. Risk Factors.
Item 1B. Unresolved Staff Comments.
Item 2. Properties.
Item 3. Legal Proceedings.
Item 4. Mine Safety Disclosures.
Part II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Item 6. Selected Financial Data.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Item 8. Financial Statements and Supplementary Data.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
Item 9A. Controls and Procedures.
Item 9B. Other Information.
Part III
Item 10. Directors, Executive Officers and Corporate Governance.
Item 11. Executive Compensation.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
Item 14. Principal Accountant Fees and Services.
Part IV
Item 15. Exhibits and Financial Statement Schedules.
Item 16. Form 10-K Summary.
EX-10.200 itc20191231ex10200.htm
EX-10.201 itc20191231ex10201.htm
EX-10.202 itc20191231ex10202.htm
EX-21 itc20191231ex21.htm
EX-31.1 itc20191231ex311.htm
EX-31.2 itc20191231ex312.htm
EX-32 itc20191231ex32.htm

ITC Holdings Earnings 2019-12-31

ITC 10K Annual Report

Balance SheetIncome StatementCash Flow

Comparables ($MM TTM)
Ticker M Cap Assets Liab Rev G Profit Net Inc EBITDA EV G Margin EV/EBITDA ROA
PINS 12,072 2,387 314 463 284 -1,201 -1,189 10,637 61% -8.9 -50%
CHWY 11,715 814 1,176 2,262 526 -112 -105 11,564 23% -109.6 -14%
WYN 10,755 7,466 8,026 3,975 1,877 464 887 15,704 47% 17.7 6%
AVTR 10,557 10,018 7,607 1,532 491 -49 168 15,861 32% 94.7 -0%
ITC 10,383 9,730 7,652 1,269 0 340 876 15,796 0% 18.0 3%
ICGL 10,171 0 1 -0 0 -4 -4 10,171 -2% -2,544.7
ATK 9,838 1,125 295 492 235 53 88 9,787 48% 111.2 5%
BYND 9,802 397 65 107 34 -16 -11 9,555 31% -902.3 -4%
TW 9,176 5,072 618 190 0 25 65 8,861 0% 135.5 0%
LEVI 8,797 3,909 2,588 5,733 3,072 402 716 8,946 54% 12.5 10%

Document
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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(Mark One)
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the fiscal year ended
December 31, 2019
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number: 001-32576
ITC HOLDINGS CORP.
(Exact Name of Registrant as Specified in Its Charter)
Michigan
 
32-0058047
(State or Other Jurisdiction of Incorporation or Organization)
 
(I.R.S. Employer Identification No.)
27175 Energy Way
Novi, Michigan 48377
(Address Of Principal Executive Offices, Including Zip Code)
(248946-3000
(Registrant’s Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
Trading Symbol(s)
Name of Each Exchange on Which Registered
None
None
None
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes þ No o
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes o No þ * (Note: the Registrant is a voluntary filer and has not been subject to the filing requirements under Section 13 or 15(d) of the Securities Exchange Act of 1934 for the preceding 12 months.)
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer
 
Accelerated filer
 
Non-accelerated filer
 
Smaller Reporting Company
 
Emerging growth company 
o
 
o
 
 
 
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes No þ
The aggregate market value of the registrant’s common stock held by non-affiliates on June 30, 2019 was $0.
All shares of outstanding common stock of ITC Holdings Corp. are held by its parent company, ITC Investment Holdings Inc., which is an indirect subsidiary of Fortis Inc. There were 224,203,112 shares of common stock, no par value, outstanding as of February 12, 2020.
DOCUMENTS INCORPORATED BY REFERENCE
None
 


Table of Contents

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

 
 
Page
 
 
 
 
 
 
 
 
 



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


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


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


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


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PART I
ITEM 1.    BUSINESS.
Overview
Our business consists primarily of the electric transmission operations of our Regulated Operating Subsidiaries. ITC Holdings was incorporated in the State of Michigan in 2002. In 2016, ITC Holdings became a wholly-owned subsidiary of ITC Investment Holdings. Fortis owns a majority indirect equity interest in ITC Investment Holdings, with GIC holding an indirect equity interest of 19.9%. Through our Regulated Operating Subsidiaries, we own and operate high-voltage electric transmission systems in Michigan’s Lower Peninsula and portions of Iowa, Minnesota, Illinois, Missouri, Kansas and Oklahoma that transmit electricity from generating stations to local distribution facilities connected to our transmission systems. Our business strategy is to own, operate, maintain and invest in transmission infrastructure in order to enhance system integrity and reliability, reduce transmission constraints and support new generating resources to interconnect to our transmission systems.
As electric transmission utilities with rates regulated by the FERC, our Regulated Operating Subsidiaries earn revenues for the use of their electric transmission systems by our customers, which include investor-owned utilities, municipalities, cooperatives, power marketers and alternative energy suppliers. As independent transmission companies, our Regulated Operating Subsidiaries are subject to rate regulation only by the FERC, and our cost-based rates are discussed in “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cost-Based Formula Rates with True-Up Mechanism.”
Development of Business
We are actively identifying and investing in transmission infrastructure required to meet reliability needs and energy policy objectives. Our long-term growth plan includes ongoing investments in our current regulated transmission systems and the identification of incremental development projects throughout North America. Refer to “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Investment and Operating Results Trends” for additional details about our long-term capital investments. Refer to the discussion of risks associated with our strategic development opportunities in “Item 1A Risk Factors.”
We expect to invest approximately $3.7 billion from 2020 through 2024 at our Regulated Operating Subsidiaries. Included in this amount are capital expenditures to: (1) maintain and replace our current transmission infrastructure; (2) enhance system integrity and reliability and accommodate load growth; (3) upgrade physical and technological grid security and (4) develop and build regional transmission infrastructure, including additional transmission facilities that will provide interconnection opportunities for generating facilities.
Through our development activities, we pursue projects in North America that are in line with our business strategy, enhance competitive wholesale electricity markets and facilitate interconnections of new generating resources, including wind generation and other renewable resources necessary to achieve state and federal policy goals. We are also actively pursuing development initiatives related to grid modernization and contracted transmission projects.
Operations
As transmission-only companies, our Regulated Operating Subsidiaries function as conduits, allowing for power from generators to be transmitted to local distribution systems either entirely through our Regulated Operating Subsidaries’ own systems or in conjunction with neighboring transmission systems. Third parties then transmit power through these local distribution systems to end-use consumers. The transmission of electricity by our Regulated Operating Subsidiaries is a central function to the provision of electricity to residential, commercial and industrial end-use consumers. The operations performed by our Regulated Operating Subsidiaries fall into the following categories:
asset planning;
engineering, design and construction;
asset protection and performance;
cyber security operations and engineering;
maintenance; and


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


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


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


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


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


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


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


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


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


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


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


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

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


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


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


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

 
$
1,192

 
$
1,226

 
$
1,142

 
$
1,025

Formula Rate true-up
41

 
(36
)
 
(15
)
 
(17
)
 
20

Total operating revenues
1,327

 
1,156

 
1,211

 
1,125

 
1,045

OPERATING EXPENSES
 
 
 
 
 
 
 
 
 
Operation and maintenance
113

 
109

 
110

 
114

 
113

General and administrative (c) (d)
138

 
127

 
121

 
234

 
140

Depreciation and amortization
203

 
180

 
169

 
158

 
145

Taxes other than income taxes
118

 
109

 
103

 
93

 
82

Other operating (income) and expense, net

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

 
521

 
501

 
598

 
479

OPERATING INCOME (d)
755

 
635

 
710

 
527

 
566

OTHER EXPENSES (INCOME)
 
 
 
 
 
 
 
 
 
Interest expense, net
224

 
224

 
224

 
211

 
204

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

 
3

 
4

 
8

 
6

Total other expenses (income) (d)
195

 
194

 
195

 
184

 
182

INCOME BEFORE INCOME TAXES
560

 
441

 
515

 
343

 
384

INCOME TAX PROVISION (e)
132

 
111

 
196

 
97

 
142

NET INCOME
$
428

 
$
330

 
$
319

 
$
246

 
$
242

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


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

 
$
6

 
$
66

 
$
8

 
$
14

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

 
7,910

 
7,309

 
6,698

 
6,110

Goodwill
950

 
950

 
950

 
950

 
950

Total assets
10,058

 
9,329

 
8,823

 
8,223

 
7,555

Debt:
 
 
 
 
 
 
 
 
 
ITC Holdings
2,968

 
2,767

 
2,728

 
2,387

 
2,304

Regulated Operating Subsidiaries
2,839

 
2,571

 
2,373

 
2,203

 
2,125

Total debt
5,807

 
5,338

 
5,101

 
4,590

 
4,429

Total stockholder’s equity
$
2,232

 
$
2,051

 
$
1,920

 
$
1,901

 
$
1,709

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

 
$
769

 
$
755

 
$
750

 
$
701

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


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


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


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

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

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

5
Income taxes (c)
 
37,500

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

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


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

 
$
3,746

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


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


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

 
$
1

 
$

Interest expense increase (decrease)
(12
)
 
7

 
6

Estimated net income increase (decrease)
61

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


29

Table of Contents

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


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Table of Contents

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

 
$
1,192

 
$
94

 
8
 %
 
$
1,226

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

 
(36
)
 
77

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

 
1,156

 
171

 
15
 %
 
1,211

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

 
109

 
4

 
4
 %
 
110

 
(1
)
 
(1
)%
General and administrative
138

 
127

 
11

 
9
 %
 
121

 
6

 
5
 %
Depreciation and amortization
203

 
180

 
23

 
13
 %
 
169

 
11

 
7
 %
Taxes other than income taxes
118

 
109

 
9

 
8
 %
 
103

 
6

 
6
 %
Other operating (income) and expenses, net

 
(4
)
 
4

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

 
521

 
51

 
10
 %
 
501

 
20

 
4
 %
OPERATING INCOME
755

 
635

 
120

 
19
 %
 
710

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

 
224

 

 
 %
 
224

 

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

 
(12
)%
 
(33
)
 

 
 %
Other (income) and expenses, net

 
3

 
(3
)
 
(100
)%
 
4

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

 
194

 
1

 
1
 %
 
195

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

 
441

 
119

 
27
 %
 
515

 
(74
)
 
(14
)%
INCOME TAX PROVISION
132

 
111

 
21

 
19