10-K 1 itc2015123110k.htm 10-K 10-K
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(Mark One)
þ
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the fiscal year ended December 31, 2015
OR
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number: 001-32576
ITC HOLDINGS CORP.
(Exact Name of Registrant as Specified in Its Charter)
Michigan
(State or Other Jurisdiction of
Incorporation or Organization)
 
32-0058047
(I.R.S. Employer
Identification No.)
27175 Energy Way
Novi, Michigan 48377
(Address Of Principal Executive Offices, Including Zip Code)
(248) 946-3000
(Registrant’s Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
Common stock, without par value
 
Name of Each Exchange on Which Registered
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act of 1933. Yes þ No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934. Yes o No þ
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information, statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer þ
 
Accelerated filer o
 
Non-accelerated filer o
 
Smaller Reporting Company o
 
 
 
 
(Do not check if a smaller reporting company)
 
 
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
The aggregate market value of the registrant’s common stock held by non-affiliates on June 30, 2015 was approximately $4.9 billion, based on the closing sale price as reported on the New York Stock Exchange. For purposes of this computation, all executive officers, directors and 10% beneficial owners of the registrant are assumed to be affiliates. Such determination should not be deemed an admission that such officers, directors and beneficial owners are, in fact, affiliates of the registrant.
The number of shares of the Registrant’s Common Stock, without par value, outstanding as of February 19, 2016 was 152,715,434.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant’s definitive Proxy Statement for the Registrant’s 2016 Annual Meeting of Shareholders (the “Proxy Statement”) filed pursuant to Regulation 14A are incorporated by reference in Part III of this Form 10-K.
 



ITC Holdings Corp.
Form 10-K for the Fiscal Year Ended December 31, 2015
INDEX

 
 
Page
 
 
 
 
 
 
 
 
 



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DEFINITIONS
Unless otherwise noted or the context requires, all references in this report to:
ITC Holdings Corp. and its subsidiaries
“ITC Great Plains” are references to ITC Great Plains, LLC, a wholly-owned subsidiary of ITC Grid Development, LLC;
“ITC Grid Development” are references to ITC Grid Development, LLC, a wholly-owned subsidiary of ITC Holdings;
“ITC Holdings” are references to ITC Holdings Corp. and not any of its subsidiaries;
“ITC Midwest” are references to ITC Midwest LLC, a wholly-owned subsidiary of ITC Holdings;
“ITCTransmission” are references to International Transmission Company, a wholly-owned subsidiary of ITC Holdings;
“METC” are references to Michigan Electric Transmission Company, LLC, a wholly-owned subsidiary of MTH;
“MISO Regulated Operating Subsidiaries” are references to ITCTransmission, METC and ITC Midwest together;
“MTH” are references to Michigan Transco Holdings, LLC, the sole member of METC and an indirect wholly-owned subsidiary of ITC Holdings;
“Regulated Operating Subsidiaries” are references to ITCTransmission, METC, ITC Midwest and ITC Great Plains together; and
“We,” “our” and “us” are references to ITC Holdings together with all of its subsidiaries.
Other definitions
“Consumers Energy” are references to Consumers Energy Company, a wholly-owned subsidiary of CMS Energy Corporation;
“DTE Electric” are references to DTE Electric Company, a wholly-owned subsidiary of DTE Energy;
“DTE Energy” are references to DTE Energy Company;
“Entergy Transaction” are references to the transaction whereby the electric transmission business of Entergy Corporation was to be separated and subsequently merged with a wholly-owned subsidiary of ITC Holdings. The proposed transaction was terminated in December 2013;
“FPA” are references to the Federal Power Act;
“FERC” are references to the Federal Energy Regulatory Commission;
“ICC” are references to the Illinois Commerce Commission;
“IP&L” are references to Interstate Power and Light Company, an Alliant Energy Corporation subsidiary;
“ISO” are references to Independent System Operators;
“IUB” are references to the Iowa Utilities Board;
“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);
“LIBOR” are references to the London Interbank Offered Rate;
“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;


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“MOPSC” are references to the Missouri Public Service Commission;
“MPSC” are references to the Michigan Public Service Commission;
“MPUC” are references to the Minnesota Public Utilities Commission;
“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;
“OCC” are references to Oklahoma Corporation Commission;
“PSCW” are references to the Public Service Commission of Wisconsin;
“RTO” are references to Regional Transmission Organizations; and
“SPP” are references to Southwest Power Pool, Inc., a FERC-approved RTO which oversees the operation of the bulk power transmission system for a substantial portion of the South Central United States, and of which ITC Great Plains is a member.

EXPLANATORY NOTE

The share and per share data in this Form 10-K reflect the three-for-one stock split that occurred on February 28, 2014.






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PART I
ITEM 1.    BUSINESS.
Overview
Our business consists primarily of the electric transmission operations of our Regulated Operating Subsidiaries. In 2002, ITC Holdings was incorporated in the State of Michigan for the purpose of acquiring ITCTransmission. ITCTransmission was originally formed in 2001 as a subsidiary of DTE Electric, an electric utility subsidiary of DTE Energy, and was acquired in 2003 by ITC Holdings. METC was originally formed in 2001 as a subsidiary of Consumers Energy, an electric and gas utility subsidiary of CMS Energy Corporation, and was acquired in 2006 by ITC Holdings. ITC Midwest was formed in 2007 by ITC Holdings to acquire the transmission assets of IP&L in December 2007. ITC Great Plains was formed in 2006 by ITC Holdings and became a FERC-jurisdictional entity in 2009. We own and operate high-voltage systems in Michigan’s Lower Peninsula and portions of Iowa, Minnesota, Illinois, Missouri, Kansas and Oklahoma that transmit electricity from generating stations to local distribution facilities connected to our systems.
Our business strategy is to own, operate, maintain and invest in transmission infrastructure in order to enhance system integrity and reliability, reduce transmission constraints and allow new generating resources to interconnect to our transmission systems. We also are pursuing development projects not within our existing systems, which are also intended to improve overall grid reliability, reduce transmission constraints and facilitate interconnections of new generating resources, as well as enhance competitive wholesale electricity markets.
As electric transmission utilities with rates regulated by the FERC, our Regulated Operating Subsidiaries earn revenues through tariff rates charged for the use of their electric transmission systems by our customers, which include investor-owned utilities, municipalities, cooperatives, power marketers and alternative energy suppliers. As independent transmission companies, our Regulated Operating Subsidiaries are subject to rate regulation only by the FERC. The rates charged by our Regulated Operating Subsidiaries are established using cost-based formula rate templates 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.”
In February 2015, we announced an internal reorganization and executive changes to support our core business focus and increase dedicated resources for grid development activities.
The Proposed Merger
On February 9, 2016, Fortis Inc. (“Fortis”), FortisUS Inc. (“FortisUS”), Element Acquisition Sub, Inc. (“Merger Sub”) and ITC Holdings entered into an agreement and plan of merger (the “Merger Agreement”), pursuant to which Merger Sub will merge with and into ITC Holdings, as a result of which ITC Holdings will become a subsidiary of FortisUS (the “Merger”). In the Merger, our shareholders will receive $22.57 in cash and 0.7520 Fortis common shares for each share of common stock of ITC Holdings. For a discussion of various risks relating to the Merger, see “Item 1A Risk Factors — Risks Relating to the Merger.” Refer to Note 20 to the consolidated financial statements for further explanation of the Merger.
Development of Business
We are actively developing transmission infrastructure required to meet reliability needs and energy policy objectives. Our long-term growth plan includes continued investment in current transmission systems, generator interconnections and our ongoing development projects. Refer to “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Investment and Operating Results Trends” for additional details about our long-term capital investments. Refer to the discussion of risks associated with our strategic development opportunities in “Item 1A Risk Factors.”
Current Transmission Systems
We expect to invest approximately $1.5 billion from 2016 through 2018 at our Regulated Operating Subsidiaries in order to maintain and replace the current transmission infrastructure, enhance system integrity and reliability and accommodate load growth.
Regional Infrastructure
We expect to invest approximately $530 million from 2016 through 2018 to develop and build regional transmission infrastructure to address system needs.


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Included in this amount are the portions of the four North Central Multi-Value Projects (“MVPs”) approved by MISO in December 2011 that we will build, own and operate, as well as the Thumb Loop Project. The four MVPs are located in south central Minnesota, northern and southeast Iowa, southwest Wisconsin, and northeast Missouri and will be constructed by ITC Midwest. We currently estimate we will invest approximately $500 million in our portions of these four MVPs from 2016 through 2018. The Thumb Loop Project, which was placed in service in May 2015, is located in ITCTransmission’s region and consists of a 140-mile, double-circuit 345 kV transmission line and related substations that are the backbone of the transmission system needed to accommodate future wind development projects in Michigan. Through December 31, 2015, ITCTransmission has invested $501.4 million in the Thumb Loop Project and any further investment to complete this project is not expected to be material.
Based on the anticipated growth of generating resources, we also foresee the need to construct additional transmission facilities that will provide interconnection opportunities for generating facilities. These investments may include, but are not limited to, the backbone transmission network, transmission for renewable resources and transmission for interconnection of other generating facilities.
Development Projects
Through our regulated grid development and merchant and international activities, we are actively pursuing projects to upgrade the existing transmission grid and regional transmission facilities, primarily to improve overall grid reliability, reduce transmission constraints, enhance competitive markets and facilitate interconnections of new generating resources, including wind generation and other renewable resources necessary to achieve state and federal policy goals. Additionally, we may pursue other non-traditional transmission investment opportunities not described above.
Segments
We have one reportable segment consisting of our Regulated Operating Subsidiaries. Additionally, we have other subsidiaries focused primarily on business development activities and a holding company whose activities include corporate debt and equity financings and certain other corporate activities. A more detailed discussion of our reportable segment, including financial information about the segment, is included in Note 18 to the consolidated financial statements.
Operations
As transmission-only companies, our Regulated Operating Subsidiaries function as conduits, allowing for power from generators to be transmitted to local distribution systems either entirely through their own systems or in conjunction with neighboring transmission systems. Third parties then transmit power through these local distribution systems to end-use consumers. The transmission of electricity by our Regulated Operating Subsidiaries is a central function to the provision of electricity to residential, commercial and industrial end-use consumers. The operations performed by our Regulated Operating Subsidiaries fall into the following categories:
asset planning;
engineering, design and construction;
maintenance; and
real time operations.
Asset Planning
The Asset Planning group uses detailed system models and load forecasts to develop our system expansion capital plans. Expansion capital plans identify projects that would address potential future reliability issues and/or produce economic savings for customers by eliminating constraints.
The Asset Planning group works closely with MISO and SPP in the development of our system expansion capital plans by performing technical evaluations and detailed studies. As the regional planning authorities, MISO and SPP approve regional system improvement plans which include projects to be constructed by their members, including our Regulated Operating Subsidiaries.
Engineering, Design and Construction
The Engineering, Design and Construction group is responsible for design, equipment specifications, maintenance plans and project engineering for capital, operation and maintenance work. We work with outside


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contractors to perform various aspects of our engineering, design and construction, but retain internal technical experts who have experience with respect to the key elements of the transmission system such as substations, lines, equipment and protective relaying systems.
Maintenance
We develop and track preventive maintenance plans to promote safe and reliable systems. By performing preventive maintenance on our assets, we can minimize the need for reactive maintenance, resulting in improved reliability. Our Regulated Operating Subsidiaries contract with Utility Lines Construction Services, Inc. (“ULCS”), which is a division of Asplundh Tree Expert Co., to perform the majority of their maintenance. The agreement with ULCS provides us with access to an experienced and scalable workforce with knowledge of our system at an established rate.
Real Time Operations
System Operations From our operations facility in Novi, Michigan, transmission system operators continuously monitor the performance of the transmission systems of our Regulated Operating Subsidiaries, using software and communication systems to perform analysis to plan for contingencies and maintain security and reliability following any unplanned events on the system. Transmission system operators are also responsible for the switching and protective tagging function, taking equipment in and out of service to ensure capital construction projects and maintenance programs can be completed safely and reliably.
Local Balancing Authority Operator — Under the functional control of MISO, ITCTransmission and METC operate their electric transmission systems as a combined Local Balancing Authority (“LBA”) area, known as the Michigan Electric Coordinated Systems (“MECS”). From our operations facility in Novi, Michigan, our employees perform the LBA functions as outlined in MISO’s Balancing Authority Agreement. These functions include actual interchange data administration and verification as well as MECS LBA area emergency procedure implementation and coordination. ITC Midwest and ITC Great Plains are not responsible for LBA functions for their respective assets.
Operating Contracts
Our Regulated Operating Subsidiaries have various operating contracts, including numerous interconnection agreements with generation and transmission providers that address terms and conditions of interconnection. The following significant agreements exist at our Regulated Operating Subsidiaries:
ITCTransmission
DTE Electric operates the electric distribution system to which ITCTransmission’s transmission system connects. A set of three operating contracts sets forth the terms and conditions related to DTE Electric’s and ITCTransmission’s ongoing working relationship. These contracts include the following:
Master Operating Agreement. The Master Operating Agreement (the “MOA”), dated as of February 28, 2003, governs the primary day-to-day operational responsibilities of ITCTransmission and DTE Electric and will remain in effect until terminated by mutual agreement of the parties (subject to any required FERC approvals) unless earlier terminated pursuant to its terms. The MOA identifies the control area coordination services that ITCTransmission is obligated to provide to DTE Electric. The MOA also requires DTE Electric to provide certain generation-based support services to ITCTransmission.
Generator Interconnection and Operation Agreement. DTE Electric and ITCTransmission entered into the Generator Interconnection and Operation Agreement (the “GIOA”), dated as of February 28, 2003, in order to establish, re-establish and maintain the direct electricity interconnection of DTE Electric’s electricity generating assets with ITCTransmission’s transmission system for the purposes of transmitting electric power from and to the electricity generating facilities. Unless otherwise terminated by mutual agreement of the parties (subject to any required FERC approvals), the GIOA will remain in effect until DTE Electric elects to terminate the agreement with respect to a particular unit or until a particular unit ceases commercial operation.
Coordination and Interconnection Agreement. The Coordination and Interconnection Agreement (the “CIA”), dated as of February 28, 2003, governs the rights, obligations and responsibilities of ITCTransmission and DTE Electric regarding, among other things, the operation and interconnection of DTE Electric’s distribution system and ITCTransmission’s transmission system, and the construction of new facilities or modification of existing facilities. Additionally, the CIA allocates costs for operation of supervisory, communications and metering


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equipment. The CIA will remain in effect until terminated by mutual agreement of the parties (subject to any required FERC approvals).
METC
Consumers Energy operates the electric distribution system to which METC’s transmission system connects. METC is a party to a number of operating contracts with Consumers Energy that govern the operations and maintenance of its transmission system. These contracts include the following:
Amended and Restated Easement Agreement. Under the Amended and Restated Easement Agreement (the “Easement Agreement”), dated as of April 29, 2002 and as further supplemented, Consumers Energy provides METC with an easement to the land, which we refer to as premises, on which a majority of METC’s transmission towers, poles, lines and other transmission facilities used to transmit electricity at voltages of at least 120 kV are located, which we refer to collectively as the facilities. Consumers Energy retained for itself the rights to, and the value of activities associated with, all other uses of the premises and the facilities covered by the Easement Agreement, such as for distribution of electricity, fiber optics, telecommunications, gas pipelines and agricultural uses. Accordingly, METC is not permitted to use the premises or the facilities covered by the Easement Agreement for any purposes other than to provide electric transmission and related services, to inspect, maintain, repair, replace and remove electric transmission facilities and to alter, improve, relocate and construct additional electric transmission facilities. The easement is further subject to the rights of any third parties that had rights to use or occupy the premises or the facilities prior to April 1, 2001 in a manner not inconsistent with METC’s permitted uses.
METC pays Consumers Energy annual rent of $10.0 million, in equal quarterly installments, for the easement and related rights under the Easement Agreement. Although METC and Consumers Energy share the use of the premises and the facilities covered by the Easement Agreement, METC pays the entire amount of any rentals, property taxes, inspection fees and other amounts required to be paid to third parties with respect to any use, occupancy, operations or other activities on the premises or the facilities and is generally responsible for the maintenance of the premises and the facilities used for electric transmission at its expense. METC also must maintain commercial general liability insurance protecting METC and Consumers Energy against claims for personal injury, death or property damage occurring on the premises or the facilities and pay for all insurance premiums. METC is also responsible for patrolling the premises and the facilities by air at its expense at least annually and to notify Consumers Energy of any unauthorized uses or encroachments discovered. METC must indemnify Consumers Energy for all liabilities arising from the facilities covered by the Easement Agreement.
METC must notify Consumers Energy before altering, improving, relocating or constructing additional transmission facilities covered by the Easement Agreement. Consumers Energy may respond by notifying METC of reasonable work and design restrictions and precautions that are needed to avoid endangering existing distribution facilities, pipelines or communications lines, in which case METC must comply with these restrictions and precautions. METC has the right at its own expense to require Consumers Energy to remove and relocate these facilities, but Consumers Energy may require payment in advance or the provision of reasonable security for payment by METC prior to removing or relocating these facilities, and Consumers Energy need not commence any relocation work until an alternative right-of-way satisfactory to Consumers Energy is obtained at METC’s expense.
The term of the Easement Agreement runs through December 31, 2050 and is subject to 10 automatic 50-year renewals after that time unless METC provides one year’s notice of its election not to renew the term. Consumers Energy may terminate the Easement Agreement 30 days after giving notice of a failure by METC to pay its quarterly installment if METC does not cure the non-payment within the 30-day notice period. At the end of the term or upon any earlier termination of the Easement Agreement, the easement and related rights terminate and the transmission facilities revert to Consumers Energy.
Amended and Restated Operating Agreement. Under the Amended and Restated Operating Agreement (the “Operating Agreement”), dated as of April 29, 2002, METC agrees to operate its transmission system to provide all transmission customers with safe, efficient, reliable and nondiscriminatory transmission service pursuant to its tariff. Among other things, METC is responsible under the Operating Agreement for maintaining and operating its transmission system, providing Consumers Energy with information and access to its transmission system and related books and records, administering and performing the duties of control area operator (that is, the entity exercising operational control over the transmission system) and, if requested by


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Consumers Energy, building connection facilities necessary to permit interaction with new distribution facilities built by Consumers Energy. Consumers Energy has corresponding obligations to provide METC with access to its books and records and to build distribution facilities necessary to provide adequate and reliable transmission services to wholesale customers. Consumers Energy must cooperate with METC as METC performs its duties as control area operator, including by providing reactive supply and voltage control from generation sources or other ancillary services and reducing load. The Operating Agreement is effective through 2050 and is subject to 10 automatic 50-year renewals after that time, unless METC provides one year’s notice of its election not to renew.
Amended and Restated Purchase and Sale Agreement for Ancillary Services. The Amended and Restated Purchase and Sale Agreement for Ancillary Services (the “Ancillary Services Agreement”) is dated as of April 29, 2002. Since METC does not own any generating facilities, it must procure ancillary services from third party suppliers, such as Consumers Energy. Currently, under the Ancillary Services Agreement, METC pays Consumers Energy for providing certain generation based services necessary to support the reliable operation of the bulk power grid, such as voltage support and generation capability and capacity to balance loads and generation. METC is not precluded from procuring these ancillary services from third party suppliers when available. The Ancillary Services Agreement is subject to rolling one-year renewals starting May 1, 2003, unless terminated by either METC or Consumers Energy with six months prior written notice.
Amended and Restated Distribution-Transmission Interconnection Agreement. The Amended and Restated Distribution-Transmission Interconnection Agreement (the “DT Interconnection Agreement”), dated April 1, 2001 and most recently amended and restated effective as of January 1, 2015, provides for the interconnection of Consumers Energy’s distribution system with METC’s transmission system and defines the continuing rights, responsibilities and obligations of the parties with respect to the use of certain of their own and the other party’s properties, assets and facilities. METC agrees to provide Consumers Energy interconnection service at agreed-upon interconnection points, and the parties have mutual responsibility for maintaining voltage and compensating for reactive power losses resulting from their respective services. The DT Interconnection Agreement is effective so long as any interconnection point is connected to METC, unless it is terminated earlier by mutual agreement of METC and Consumers Energy.
Amended and Restated Generator Interconnection Agreement. The Amended and Restated Generator Interconnection Agreement (the “Generator Interconnection Agreement”), dated as of April 29, 2002 and most recently amended effective as of October 1, 2015, specifies the terms and conditions under which Consumers Energy and METC maintain the interconnection of Consumers Energy’s generation resources and METC’s transmission assets. The Generator Interconnection Agreement is effective either until it is replaced by any MISO-required contract, or until mutually agreed by METC and Consumers Energy to terminate, but not later than the date that all listed generators cease commercial operation.
ITC Midwest
IP&L operates the electric distribution system to which ITC Midwest’s transmission system connects. ITC Midwest is a party to a number of operating contracts with IP&L that govern the operations and maintenance of its transmission system. These contracts include the following:
Distribution-Transmission Interconnection Agreement. The Distribution-Transmission Interconnection Agreement (the “DTIA”), dated as of December 17, 2007 and amended and restated effective as of February 21, 2015, governs the rights, responsibilities and obligations of ITC Midwest and IP&L, with respect to the use of certain of their own and the other parties’ property, assets and facilities and the construction of new facilities or modification of existing facilities. Additionally, the DTIA sets forth the terms pursuant to which the equipment and facilities and the interconnection equipment of IP&L will continue to connect ITC Midwest’s facilities through which ITC Midwest provides transmission service under the MISO Transmission and Energy Markets Tariff. The DTIA will remain in effect until terminated by mutual agreement by the parties (subject to any required FERC approvals) or as long as any interconnection point of IP&L is connected to ITC Midwest’s facilities, unless modified by written agreement of the parties.
Large Generator Interconnection Agreement. ITC Midwest, IP&L and MISO entered into the Large Generator Interconnection Agreement (the “LGIA”), dated as of December 20, 2007 and amended as of August 6, 2013, in order to establish, re-establish and maintain the direct electricity interconnection of IP&L’s electricity generating assets with ITC Midwest’s transmission system for the purposes of transmitting electric power from


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and to the electricity generating facilities. The LGIA will remain in effect until terminated by ITC Midwest or until IP&L elects to terminate the agreement if a particular unit ceases commercial operation for three consecutive years.
Operations Services Agreement For 34.5 kV Transmission Facilities. ITC Midwest and IP&L entered into the Operations Services Agreement for 34.5 kV Transmission Facilities (the “OSA”), effective as of January 1, 2011, under which IP&L performs certain operations functions for ITC Midwest’s 34.5 kV transmission system on behalf of ITC Midwest. The OSA provides that when ITC Midwest upgrades 34.5 kV facilities to higher operating voltages it may notify IP&L of the change and the OSA is no longer applicable to those facilities. The OSA will remain in full force and effect until December 31, 2015 and will extend automatically from year to year thereafter until terminated by either party upon not less than one year prior written notice to the other party.
ITC Great Plains
Amended and Restated Maintenance Agreement. Mid-Kansas Electric Company LLC (“Mid-Kansas”) and ITC Great Plains have entered into a Maintenance Agreement (the “Mid-Kansas Agreement”), dated as of August 24, 2010, and most recently amended effective as of June 1, 2015, pursuant to which Mid-Kansas has agreed to perform various field operations and maintenance services related to certain ITC Great Plains facilities. The Mid-Kansas Agreement has an initial term of 10 years and automatic 10-year renewals unless terminated (1) due to a breach by the non-terminating party following notice and failure to cure, (2) by mutual consent of the parties, or (3) by ITC Great Plains under certain limited circumstances. Services must continue to be provided for at least six months subsequent to the termination date in any case.
Regulatory Environment
Many regulators and public policy makers support the need for further investment in the transmission grid. The growth and changing mix of electricity generation, wholesale power sales and consumption combined with historically inadequate transmission investment have resulted in significant transmission constraints across the United States and increased stress on aging equipment. These problems will continue without increased investment in transmission infrastructure. Transmission system investments can also increase system reliability and reduce the frequency of power outages. Such investments can reduce transmission constraints and improve access to lower cost generation resources, resulting in a lower overall cost of delivered electricity for end-use consumers. After the 2003 blackout that affected sections of the Northeastern and Midwestern United States and Ontario, Canada, the Department of Energy (the “DOE”) established the Office of Electric Transmission and Distribution (now the Office of Electricity Delivery and Energy Reliability), focused on working with reliability experts from the power industry, state governments and their Canadian counterparts to improve grid reliability and increase investment in the country’s electric infrastructure. In addition, the FERC has signaled its desire for substantial new investment in the transmission sector by implementing various financial and other incentives.
The FERC has also issued orders to promote non-discriminatory transmission access for all transmission customers. In the United States, electric transmission assets are predominantly owned, operated and maintained by utilities that also own electricity generation and distribution assets, known as vertically integrated utilities. The FERC has recognized that the vertically-integrated utility model inhibits the provision of non-discriminatory transmission access and, in order to alleviate this potential discrimination, the FERC has mandated that all transmission systems over which it has jurisdiction must be operated in a comparable, non-discriminatory manner such that any seller of electricity affiliated with a transmission owner (“TO”) or operator is not provided with preferential treatment. The FERC has also indicated that independent transmission companies can play a prominent role in furthering its policy goals and has encouraged the legal and functional separation of transmission operations from generation and distribution operations.
The FERC requires compliance with certain reliability standards by transmission owners and may take enforcement actions for violations, including the imposition of substantial fines. NERC is responsible for developing and enforcing these mandatory reliability standards. We continually assess our transmission systems against standards established by NERC, as well as the standards of applicable regional entities under NERC that have been delegated certain authority for the purpose of proposing and enforcing reliability standards. Finally, utility holding companies are subject to FERC regulations related to access to books and records in addition to the requirement of the FERC to review and approve mergers and consolidations involving utility assets and holding companies in certain circumstances.


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Federal Regulation
As electric transmission companies, our Regulated Operating Subsidiaries are regulated by the FERC. The FERC is an independent regulatory commission within the DOE that regulates the interstate transmission and certain wholesale sales of natural gas, the transmission of oil and oil products by pipeline and the transmission and wholesale sales of electricity in interstate commerce. The FERC also administers accounting and financial reporting regulations and standards of conduct for the companies it regulates. In 1996, in order to facilitate open access transmission for participants in wholesale power markets, the FERC issued Order No. 888. The open access policy promulgated by the FERC in Order No. 888 was upheld in a United States Supreme Court decision, State of New York vs. FERC, issued on March 4, 2002. To facilitate open access, among other things, FERC Order No. 888 encouraged investor owned utilities to cede operational control over their transmission systems to ISOs, which are not-for-profit entities.
As an alternative to ceding operating control of their transmission assets to ISOs, certain investor owned utilities began to promote the formation of for-profit transmission companies, which would assume control of the operation of the grid. In December 1999, the FERC issued Order No. 2000, which strongly encouraged utilities to voluntarily transfer operational control of their transmission systems to RTOs. RTOs, as envisioned in Order No. 2000, would assume many of the functions of an ISO, but the FERC permitted greater flexibility with regard to the organization and structure of RTOs than it had for ISOs. RTOs could accommodate the inclusion of independently owned, for-profit companies that own transmission assets within their operating structure. Independent ownership would facilitate not only the independent operation of the transmission systems, but also the formation of companies with a greater financial interest in maintaining and augmenting the capacity and reliability of those systems. RTOs such as MISO and SPP monitor electric reliability and are responsible for coordinating the operation of the wholesale electric transmission system and ensuring fair, non-discriminatory access to the transmission grid.
FERC Order No. 1000 (“Order 1000”) amends certain existing transmission planning and cost allocation requirements to ensure that FERC-jurisdictional services are provided at just and reasonable rates and on a basis that is just and reasonable and not unduly discriminatory or preferential. With respect to transmission planning, Order 1000: (1) requires that each public utility transmission provider participate in a regional transmission planning process that produces a regional transmission plan; (2) requires that each public utility transmission provider amend its Open Access Transmission Tariff to describe procedures that provide for the consideration of transmission needs driven by public policy requirements in the local and regional transmission planning processes; (3) removes a federal right of first refusal for certain new transmission facilities from FERC-approved tariffs and agreements; and (4) improves coordination between neighboring transmission planning regions for new interregional transmission facilities. MISO and SPP are compliant with the regional requirements of Order 1000 after making multiple compliance filings at FERC; however, MISO and SPP must make further compliance filings to comply with interregional Order 1000 requirements.
Order 1000 could potentially lead to greater competition for certain future transmission projects, including within our current operating areas. We are currently exploring opportunities resulting from Order 1000 within MISO and SPP as well as other RTOs.
Revenue Requirement Calculations and Cost Sharing for Projects with Regional Benefits
The cost based formula rates used by our Regulated Operating Subsidiaries include revenue requirement calculations for various types of projects. Network revenues continue to be the largest component of revenues recovered through our formula rates. However, regional cost sharing revenues are growing as a result of projects that have been identified by MISO or SPP as having regional benefits, and therefore eligible for regional cost recovery under their tariffs. Separate calculations of revenue requirement are performed for projects that have been approved for regional cost sharing and impact only which parties ultimately pay for the transmission services related to these projects and do not impact our financial results.
We have projects that are eligible for regional cost sharing under the MISO tariff, such as certain network upgrade projects, and the MVPs, including the four North Central MVPs and the Thumb Loop Project. Additionally, certain projects at ITC Great Plains are eligible for recovery through a region-wide charge in the SPP tariff, including the Kansas V-Plan Project. Certain of these projects are described in more detail in “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Project Updates and Other Recent Developments.”


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State Regulation
The regulatory agencies in the states where our Regulated Operating Subsidiaries’ assets are located do not have jurisdiction over our rates or terms and conditions of service. However, they typically have jurisdiction over siting of transmission facilities and related matters as described below. Additionally, we are subject to the regulatory oversight of various state environmental quality departments for compliance with any state environmental standards and regulations.
ITCTransmission and METC
Michigan
The MPSC has jurisdiction over the siting of certain transmission facilities. Additionally, ITCTransmission and METC 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 and METC are also subject to the regulatory oversight of the Michigan Department of Environmental Quality, the Michigan Department of Natural Resources and certain local authorities for compliance with all environmental standards and regulations.
ITC Midwest
Iowa
The IUB has the power of supervision over the construction, operation and maintenance of transmission facilities in Iowa by any entity, which includes the power to issue franchises. Iowa law further provides that any entity granted a franchise by the IUB is vested with the power of condemnation in Iowa to the extent the IUB approves and deems necessary for public use. A city has the power, pursuant to Iowa law, to grant a franchise to erect, maintain and operate transmission facilities within the city, which franchise may regulate the conditions required and manner of use of the streets and public grounds of the city and may confer the power to appropriate and condemn private property.
ITC Midwest also is subject to the regulatory oversight of certain state agencies (including the Iowa Department of Natural Resources) and certain local authorities with respect to the issuance of environmental, highway, railroad and similar permits.
Minnesota
The MPUC has jurisdiction over the construction, siting and routing of new transmission lines or upgrades of existing lines through Minnesota’s Certificate of Need and Route Permit Processes. Transmission companies are also required to participate in the State’s Biennial Transmission Planning Process and are subject to the state’s preventative maintenance requirements. Pursuant to Minnesota law, ITC Midwest has the right as an independent transmission company to condemn property in the State of Minnesota for the purpose of building new transmission facilities.
ITC Midwest is also subject to the regulatory oversight of the Minnesota Pollution Control Agency, the Minnesota Department of Natural Resources, the MPUC in conjunction with the Department of Commerce and certain local authorities for compliance with applicable environmental standards and regulations.
Illinois
The ICC exercises jurisdiction over siting of new transmission lines through its requirements for Certificates of Public Convenience and Necessity and Right-Of-Way acquisition that apply to construction of new or upgraded facilities.
ITC Midwest also is subject to the regulatory oversight of the Illinois Environmental Protection Agency, the Illinois Department of Natural Resources, the Illinois Pollution Control Board and certain local authorities for compliance with all environmental standards and regulations.
Missouri
Because ITC Midwest is a “public utility” and an “electrical corporation” under Missouri law, the MOPSC has jurisdiction to determine whether ITC Midwest may operate in such capacity. The MOPSC also exercises jurisdiction


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with regard to other non-rate matters affecting this Missouri asset such as transmission substation construction, general safety and the transfer of the franchise or property.
ITC Midwest is also subject to the regulatory oversight of the Missouri Department of Natural Resources for compliance with all environmental standards and regulations relating to this transmission line.
Wisconsin
ITC Midwest is a “public utility” and independent transmission owner in Wisconsin. The PSCW in a May 2014 order granted ITC Midwest a certificate of authority to transact public utility business in the state. In a separate May 2014 order, the PSCW also recognized ITC Holdings Corp. as a public utility holding company under Wisconsin statutes.
The PSCW exercises jurisdiction over the siting of new transmission lines through the issuance of certificates of authority and certificates of public convenience and necessity. Upon receipt of such certificates for a transmission project, ITC Midwest has condemnation authority as a foreign transmission provider under Wisconsin law. ITC Midwest is also subject to the jurisdiction of certain local and state agencies, including the Wisconsin Department of Natural Resources, relating to environmental and road permits.
ITC Great Plains
Kansas
ITC Great Plains is a “public utility” in Kansas and an “electric utility” pursuant to state statutes. The KCC issued an order approving the issuance of a limited certificate of convenience to ITC Great Plains for the purposes of building, owning and operating SPP transmission projects in Kansas. In addition to its certificate of authority, the KCC has jurisdiction over the siting of electric transmission lines.
ITC Great Plains is also subject to the regulatory oversight of the Kansas Department of Health and Environment for compliance with all environmental standards and regulations relating to the construction phase of any transmission line.
Oklahoma
ITC Great Plains has approval from the OCC to operate in Oklahoma, pursuant to Oklahoma Statutes as an electric public utility providing only transmission services. The OCC does not exercise jurisdiction over the siting of any transmission lines.
ITC Great Plains may be subject to the regulatory oversight of Oklahoma Department of Environmental Quality for compliance with environmental standards and regulations relating to construction of proposed transmission lines.
Sources of Revenue
See “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations — Operating Revenues” for a discussion of our principal sources of revenue.
Seasonality
The cost-based formula rates with a true-up mechanism in effect for all our Regulated Operating Subsidiaries, as discussed in “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cost-Based Formula Rates with True-Up Mechanism,” mitigate the seasonality of net income for our Regulated Operating Subsidiaries. Our Regulated Operating Subsidiaries accrue or defer revenues to the extent that the actual revenue requirement for the reporting period is higher or lower, respectively, than the amounts billed relating to that reporting period. For example, to the extent that amounts billed are less than our revenue requirement for a reporting period, a revenue accrual is recorded for the difference and the difference results in no net income impact.
Operating cash flows are seasonal at our MISO Regulated Operating Subsidiaries, in that cash received for revenues is typically higher in the summer months when peak load is higher.
Principal Customers
Our principal transmission service customers are DTE Electric, Consumers Energy and IP&L, which accounted for approximately 20.8%, 21.9% and 26.8%, respectively, of our consolidated billed revenues for the year ended


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December 31, 2015. 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 2013 revenue accruals and deferrals and exclude any amounts for the 2015 revenue accruals and deferrals that were included in our 2015 operating revenues, but will not be billed to our customers until 2017. Refer to Item 7 Managements Discussion and Analysis of Financial Condition and Results of Operations — Cost-Based Formula Rates with True-Up Mechanism for a discussion on the difference between billed revenues and operating revenues. Our remaining revenues were generated from providing service to other entities such as alternative electricity suppliers, power marketers and other wholesale customers that provide electricity to end-use consumers and from transaction-based capacity reservations. Nearly all of our revenues are from transmission customers in the United States. Although we may recognize allocated revenues from time to time from Canadian entities reserving transmission over the Ontario or Manitoba interface, these revenues have not been and are not expected to be material to us.
Billing
MISO and SPP are responsible for billing and collecting the majority of our transmission service revenues as well as independently administer the transmission tariff in their respective service territory. As the billing agents for our Regulated Operating Subsidiaries, MISO and SPP independently bill DTE Electric, Consumers Energy, IP&L and other customers on a monthly basis and collect fees for the use of our transmission systems.
See “Item 7A Quantitative and Qualitative Disclosures about Market Risk — Credit Risk” for discussion of our credit policies.
Competition
Each of our MISO Regulated Operating Subsidiaries operates the primary transmission system in its respective service area and has limited competition for certain projects. However, the competitive environment is evolving due to the implementation of Order 1000. See further discussion of Order 1000 above under “Regulatory Environment — Federal Regulation.” For our subsidiaries focused on development opportunities for transmission investment in other service areas, the incumbent utilities or other entities with transmission development initiatives may compete with us by seeking approval to be named the party authorized to build new capital projects that we are also pursuing. Because our Regulated Operating Subsidiaries are currently the only transmission companies that are independent from electricity market participants, we believe that we are best able to develop these projects in a non-discriminatory manner. However, there are no assurances that we will be selected to develop projects other entities are also pursuing.
Employees
As of December 31, 2015, we had 637 employees. We consider our relations with our employees to be good.
Environmental Matters
We are subject to federal, state and local environmental laws and regulations, which impose limitations on the discharge of pollutants into the environment, establish standards for the management, treatment, storage, transportation and disposal of solid and hazardous wastes and hazardous materials, and impose obligations to investigate and remediate contamination in certain circumstances. Liabilities relating to investigation and remediation of contamination, as well as other liabilities concerning hazardous materials or contamination, such as claims for personal injury or property damage, may arise at many locations, including formerly owned or operated properties and sites where wastes have been treated or disposed of, as well as properties currently owned or operated by us. Such liabilities may arise even where the contamination does not result from noncompliance with applicable environmental laws. Under some environmental laws, such liabilities may also be joint and several, meaning that a party can be held responsible for more than its share of the liability involved, or even the entire share. Although environmental requirements generally have become more stringent and compliance with those requirements more expensive, we are not aware of any specific developments that would increase our costs for such compliance in a manner that would be expected to have a material adverse effect on our results of operations, financial position or liquidity.
Our assets and operations also involve the use of materials classified as hazardous, toxic or otherwise dangerous. Many of the properties that we own or operate have been used for many years, and include older facilities and equipment that may be more likely than newer ones to contain or be made from such materials. Some of these properties include aboveground or underground storage tanks and associated piping. Some of them also


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include large electrical equipment filled with mineral oil, which may contain or previously have contained polychlorinated biphenyls, or PCBs. Our facilities and equipment are often situated on or near property owned by others so that, if they are the source of contamination, others’ property may be affected. For example, aboveground and underground transmission lines sometimes traverse properties that we do not own and transmission assets that we own or operate are sometimes commingled at our transmission stations with distribution assets owned or operated by our transmission customers.
Some properties in which we have an ownership interest or at which we operate are, or are suspected of being, affected by environmental contamination. We are not aware of any pending or threatened claims against us with respect to environmental contamination relating to these properties, or of any investigation or remediation of contamination at these properties, that entail costs likely to materially affect us. Some facilities and properties are located near environmentally sensitive areas such as wetlands.
Claims have been made or threatened against electric utilities for bodily injury, disease or other damages allegedly related to exposure to electromagnetic fields associated with electric transmission and distribution lines. While we do not believe that a causal link between electromagnetic field exposure and injury has been generally established and accepted in the scientific community, the liabilities and costs imposed on our business could be significant if such a relationship is established or accepted. We are not aware of any pending or threatened claims against us for bodily injury, disease or other damages allegedly related to exposure to electromagnetic fields and electric transmission and distribution lines that entail costs likely to have a material adverse effect on our results of operations, financial position or liquidity.
Filings Under the Securities Exchange Act of 1934
Our internet address is http://www.itc-holdings.com. All of our reports filed pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), including our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports, can be accessed free of charge on our website. These reports are available as soon as practicable after they are electronically filed with the Securities and Exchange Commission (the “SEC”). Our website also has posted our:
Corporate Governance Guidelines;
Code of Business Conduct and Ethics; and
Committee Charters for the Audit and Finance Committee, Compensation Committee and Nominating/Corporate Governance Committee.
Our Code of Business Conduct and Ethics applies to all directors, officers and employees, including our Chairman, President and Chief Executive Officer and our Senior Vice President and Chief Financial Officer. We will post any amendments to the Code of Business Conduct and Ethics, and any waivers that are required to be disclosed by the rules of either the SEC or the New York Stock Exchange (the “NYSE”), on our website within the required periods. The information on our website is not incorporated by reference into this report.
To learn more about us, please visit our website at http://www.itc-holdings.com. We use our website as a channel of distribution of material company information. Financial and other material information regarding us is routinely posted on our website and is readily accessible.
The public may also read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington DC, 20549. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC also maintains a website that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC. The internet address is http://www.sec.gov.
ITEM 1A.     RISK FACTORS.
Risks Related to Our Business
Certain elements of our Regulated Operating Subsidiaries’ formula rates can be and have been challenged, which could result in lowered rates and/or refunds of amounts previously collected and thus have an adverse effect on our business, financial condition, results of operations and cash flows.
Our Regulated Operating Subsidiaries provide transmission service under rates regulated by the FERC. The FERC has approved the cost-based formula rate templates used by our Regulated Operating Subsidiaries to


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calculate their respective annual revenue requirements, but it has not expressly approved the amount of actual capital and operating expenditures to be used in the formula rates. All aspects of our Regulated Operating Subsidiaries’ rates approved by the FERC, including the formula rate templates, the rates of return on the actual equity portion of their respective capital structures and the approved targeted capital structures, are subject to challenge by interested parties at the FERC, or by the FERC on its own initiative in a proceeding under Section 206 of the FPA. In addition, interested parties may challenge the annual implementation and calculation by our Regulated Operating Subsidiaries of their projected rates and formula rate true up pursuant to their approved formula rate templates under the Regulated Operating Subsidiaries' formula rate implementation protocols. End-use consumers and entities supplying electricity to end-use consumers may also attempt to influence government and/or regulators to change the rate setting methodologies that apply to our Regulated Operating Subsidiaries, particularly if rates for delivered electricity increase substantially. If a challenger can establish that any of these aspects are unjust, unreasonable, unduly discriminatory or preferential, then the FERC will make appropriate prospective adjustments to them and/or disallow any of our Regulated Operating Subsidiaries’ inclusion of those aspects in the rate setting formula. This could result in lowered rates and/or refunds of amounts collected, any of which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
In November 2013, certain parties filed a joint complaint with the FERC under Section 206 of the FPA, requesting that the FERC find the base rate of return on equity for all MISO transmission owners, including ITCTransmission, METC and ITC Midwest, to be unjust and unreasonable. The joint complainants sought a FERC order reducing the base rate of return on equity used in the MISO transmission owners’ formula transmission rate, reducing the targeted equity component of MISO transmission owners’ capital structures and terminating the return on equity adders approved for ITCTransmission and METC. Although the FERC issued an order rejecting this complaint as to the capital structures and ITCTransmission's and METC’s equity adders, a hearing was ordered on the complaint's allegations as to the base rate of return on equity for all MISO transmission owners. On December 22, 2015, the presiding administrative law judge issued an initial decision recommending to the FERC a reduction in the base return on equity rate of the MISO transmission owners from 12.38% to 10.32%, with a maximum rate of 11.35%. The presiding administrative law judge's initial decision is a non-binding recommendation to FERC for resolution of the matters set for hearing. A decision on the complaint from FERC is anticipated in the third quarter of 2016. In February 2015, an additional complaint was filed under Section 206 of the FPA seeking a FERC order reducing the base return on equity rate for all MISO transmission owners, including for our MISO Regulated Operating Subsidiaries, to 8.67%. A decision from FERC on the February 2015 complaint is anticipated in 2017. In each case, if any refunds are required, the refund effective date would be the date on which the related complaint was filed. In 2015 and 2014, we adjusted revenues downward to accrue for the refund liability based on our estimate of the outcome of these complaints. An unfavorable resolution of these complaints in excess of the amount accrued for the refund liability could significantly reduce our future revenues and net income and therefore could have a material adverse effect on our future results of operations, cash flows and financial condition.
Our actual capital investment may be lower than planned, which would cause a lower than anticipated rate base and would therefore result in lower revenues and earnings compared to our current expectations. In addition, we expect to invest in strategic development opportunities to improve the efficiency and reliability of the transmission grid, but we cannot provide assurance that we will be able to initiate or complete any of these investments. In addition, we expect to incur expenses related to the pursuit of development opportunities, which may be higher than forecasted.
Each of our operating subsidiaries’ rate base, revenues and earnings are determined in part by additions to property, plant and equipment and when those additions are placed in service. We anticipate making significant capital investments over the next several years; however, the amounts could change significantly due to factors beyond our control. If our operating subsidiaries’ capital investment and the resulting in-service property, plant and equipment are lower than anticipated for any reason, our operating subsidiaries will have a lower than anticipated rate base, thus causing their revenue requirements and future earnings to be lower than anticipated.
We are pursuing broader strategic development investment opportunities including those related to building regional transmission facilities and interconnections for generating resources, among others. Incumbent utilities or other transmission development entities may compete with us for regulatory approval to develop capital projects that we are pursuing. If we are unable to compete successfully for approval of these projects, our opportunities to expand our rate base and increase our revenues and earnings may become limited.


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Any capital investment at our operating subsidiaries or as a result of our broader strategic development initiatives may be lower than our published estimates due to, among other factors, the impact of actual loads, forecasted loads, regional economic conditions, weather conditions, union strikes, labor shortages, material and equipment prices and availability, our ability to obtain financing for such expenditures, if necessary, limitations on the amount of construction that can be undertaken on our system or transmission systems owned by others at any one time, regulatory requirements relating to our rate construct, environmental issues, siting, regional planning, cost recovery or other issues, or as a result of legal proceedings and variances between estimated and actual costs of construction contracts awarded and the potential for greater competition. Our ability to engage in construction projects resulting from pursuing these initiatives is subject to significant uncertainties, including the factors discussed above, and will depend on obtaining any necessary regulatory and other approvals for the project and for us to initiate construction, our achieving status as the builder of the project in some circumstances and other factors. Therefore, we can provide no assurance as to the actual level of investment we may achieve at our operating subsidiaries or as a result of the broader strategic development initiatives.
In addition, we expect to incur expenses to pursue strategic development investment opportunities. If these expenses are higher than anticipated, our future results of operations, cash flows and financial condition could be materially and adversely affected.
The regulations to which we are subject may limit our ability to raise capital and/or pursue acquisitions, development opportunities or other transactions or may subject us to liabilities.
Each of our Regulated Operating Subsidiaries is a “public utility” under the FPA and, accordingly, is subject to regulation by the FERC. Approval of the FERC is required under Section 203 of the FPA for a disposition or acquisition of regulated public utility facilities, either directly or indirectly through a holding company. Such approval is also required to acquire a significant interest in securities of a public utility. Section 203 of the FPA also provides the FERC with explicit authority over utility holding companies’ purchases or acquisitions of, and mergers or consolidations with, a public utility. Finally, each of our Regulated Operating Subsidiaries must also seek approval by the FERC under Section 204 of the FPA for issuances of its securities (including debt securities).
We are also pursuing development projects for construction of transmission facilities and interconnections with generating resources. These projects may require regulatory approval by Federal agencies, including the FERC, applicable RTOs and state and local regulatory agencies. Failure to secure such regulatory approval for new strategic development projects could adversely affect our ability to grow our business and increase our revenues. If we fail to obtain these approvals when necessary, we may incur liabilities for such failure.
Changes in energy laws, regulations or policies could impact our business, financial condition, results of operations and cash flows.
Each of our Regulated Operating Subsidiaries is regulated by the FERC as a “public utility” under the FPA and is a transmission owner in MISO or SPP. We cannot predict whether the approved rate methodologies for any of our Regulated Operating Subsidiaries will be changed. In addition, the U.S. Congress periodically considers enacting energy legislation that could assign new responsibilities to the FERC, modify provisions of the FPA or provide the FERC or another entity with increased authority to regulate transmission matters. We cannot predict whether, and to what extent, our Regulated Operating Subsidiaries may be affected by any such changes in federal energy laws, regulations or policies in the future. While our Regulated Operating Subsidiaries are subject to FERC’s exclusive jurisdiction for purposes of rate regulation, changes in state laws affecting other matters, such as transmission siting and construction, could limit investment opportunities available to us.
If amounts billed for transmission service for our Regulated Operating Subsidiaries’ transmission systems are lower than expected, or our actual revenue requirements are higher than expected, the timing of collection of our revenues would be delayed.
If amounts billed for transmission service are lower than expected, which could result from lower network load or point-to-point transmission service on our Regulated Operating Subsidiaries’ transmission systems due to a weak economy, changes in the nature or composition of the transmission assets of our Regulated Operating Subsidiaries and surrounding areas, poor transmission quality of neighboring transmission systems, or for any other reason, the timing of the collection of our revenue requirement would likely be delayed until such circumstances are adjusted through the true-up mechanism in our Regulated Operating Subsidiaries’ formula rate templates. In addition, if the revenue requirements of our Regulated Operating Subsidiaries are higher than expected, due to higher actual expenditures compared to the forecasted expenditures used to develop their billing rates or for any


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other reason, the timing of the collection of our Regulated Operating Subsidiaries' revenue requirements would likely be delayed until such circumstances are reflected through the true-up mechanism in our Regulated Operating Subsidiaries' expected, formula rate templates. The effect of such under-collection would be to reduce the amount of our available cash resources from what we had expected, until such under-collection is corrected through the true-up mechanism in the formula rate template, which may require us to increase our outstanding indebtedness, thereby reducing our available borrowing capacity, and may require us to pay interest at a rate that exceeds the interest to which we are entitled in connection with the operation of the true-up mechanism.
Each of our MISO Regulated Operating Subsidiaries depends on its primary customer for a substantial portion of its revenues, and any material failure by those primary customers to make payments for transmission services could have a material adverse effect on our business, financial condition, results of operations and cash flows.
ITCTransmission derives a substantial portion of its revenues from the transmission of electricity to DTE Electric’s local distribution facilities. DTE Electric accounted for approximately 60.3% of ITCTransmission’s total billed revenues for the year ended December 31, 2015 and is expected to constitute the majority of ITCTransmission’s revenues for the foreseeable future. DTE Electric is rated BBB+/stable and A2/stable by Standard and Poor’s Ratings Services and Moody’s Investors Services, Inc., respectively. Similarly, Consumers Energy accounted for approximately 74.6% of METC’s total billed revenues for the year ended December 31, 2015 and is expected to constitute the majority of METC’s revenues for the foreseeable future. Consumers Energy is rated BBB+/stable and A3/stable by Standard and Poor’s Ratings Services and Moody’s Investors Services, Inc., respectively. Further, IP&L accounted for approximately 78.5% of ITC Midwest’s total billed revenues for the year ended December 31, 2015 and is expected to constitute the majority of ITC Midwest’s revenues for the foreseeable future. IP&L is rated A-/stable and A3/negative by Standard and Poor’s Ratings Services and Moody’s Investors Services, Inc., respectively. These percentages of total billed revenues of DTE Electric, Consumers Energy and IP&L include the collection of 2013 revenue accruals and deferrals and exclude any amounts for the 2015 revenue accruals and deferrals that were included in our 2015 operating revenues, but will not be billed to our customers until 2017.
Any material failure by DTE Electric, Consumers Energy or IP&L to make payments for transmission services could have an adverse effect on our business, financial condition, results of operations and cash flows.
A significant amount of the land on which our assets are located is subject to easements, mineral rights and other similar encumbrances. As a result, we must comply with the provisions of various easements, mineral rights and other similar encumbrances, which may adversely impact their ability to complete construction projects in a timely manner.
METC does not own the majority of the land on which its electric transmission assets are located. Instead, under the provisions of an Easement Agreement with Consumers Energy, METC pays annual rent of $10.0 million to Consumers Energy in exchange for rights-of-way, leases, fee interests and licenses which allow METC to use the land on which its transmission lines are located. Under the terms of the Easement Agreement, METC’s easement rights could be eliminated if METC fails to meet certain requirements, such as paying contractual rent to Consumers Energy in a timely manner. Additionally, a significant amount of the land on which our other subsidiaries’ assets are located is subject to easements, mineral rights and other similar encumbrances. As a result, they must comply with the provisions of various easements, mineral rights and other similar encumbrances, which may adversely impact their ability to complete their construction projects in a timely manner.
We contract with third parties to provide services for certain aspects of our business. If any of these agreements are terminated, we may face a shortage of labor or replacement contractors to provide the services formerly provided by these third parties.
We enter into various agreements and arrangements with third parties to provide services for construction, maintenance and operations of certain aspects of our business, which, if terminated, could result in a shortage of a readily available workforce to provide these services. If any of these agreements or arrangements is terminated for any reason, we may face difficulty finding a qualified replacement work force to provide such services, which could have an adverse effect on our ability to carry on our business and on our results of operations.


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Hazards associated with high-voltage electricity transmission may result in suspension of our operations or the imposition of civil or criminal penalties.
Our operations are subject to the usual hazards associated with high-voltage electricity transmission, including explosions, fires, inclement weather, natural disasters, mechanical failure, unscheduled downtime, equipment interruptions, remediation, chemical spills, discharges or releases of toxic or hazardous substances or gases and other environmental risks. The hazards can cause personal injury and loss of life, severe damage to or destruction of property and equipment and environmental damage, and may result in suspension of operations and the imposition of civil or criminal penalties. We maintain property and casualty insurance, but we are not fully insured against all potential hazards incident to our business, such as damage to poles, towers and lines or losses caused by outages.
We are subject to environmental regulations and to laws that can give rise to substantial liabilities from environmental contamination.
We are subject to federal, state and local environmental laws and regulations, which impose limitations on the discharge of pollutants into the environment, establish standards for the management, treatment, storage, transportation and disposal of solid and hazardous wastes and hazardous materials, and impose obligations to investigate and remediate contamination in certain circumstances. Liabilities relating to investigation and remediation of contamination, as well as other liabilities concerning hazardous materials or contamination such as claims for personal injury or property damage, may arise at many locations, including formerly owned or operated properties and sites where wastes have been treated or disposed of, as well as properties we currently own or operate. Such liabilities may arise even where the contamination does not result from noncompliance with applicable environmental laws. Under a number of environmental laws, such liabilities may also be joint and several, meaning that a party can be held responsible for more than its share of the liability involved, or even the entire share. Environmental requirements generally have become more stringent in recent years, and compliance with those requirements more expensive.
We have incurred expenses in connection with environmental compliance, and we anticipate that we will continue to do so in the future. Failure to comply with the extensive environmental laws and regulations applicable to us could result in significant civil or criminal penalties and remediation costs. Our assets and operations also involve the use of materials classified as hazardous, toxic or otherwise dangerous. Some of our facilities and properties are located near environmentally sensitive areas such as wetlands and habitats of endangered or threatened species. In addition, certain properties in which we operate are, or are suspected of being, affected by environmental contamination. Compliance with these laws and regulations, and liabilities concerning contamination or hazardous materials, may adversely affect our costs and, therefore, our business, financial condition and results of operations.
In addition, claims have been made or threatened against electric utilities for bodily injury, disease or other damages allegedly related to exposure to electromagnetic fields associated with electric transmission and distribution lines. We cannot provide assurance that such claims will not be asserted against us or that, if determined in a manner adverse to our interests, such claims would not have a material effect on our business, financial condition and results of operations.
We are subject to various regulatory requirements, including reliability standards; contract filing requirements; reporting, recordkeeping and accounting requirements; and transaction approval requirements. Violations of these requirements, whether intentional or unintentional, may result in penalties that, under some circumstances, could have a material adverse effect on our business, financial condition, results of operations and cash flows.
The various regulatory requirements to which we are subject include reliability standards established by the NERC, which acts as the nation’s Electric Reliability Organization approved by the FERC in accordance with Section 215 of the FPA. These standards address operation, planning and security of the bulk power system, including requirements with respect to real-time transmission operations, emergency operations, vegetation management, critical infrastructure protection and personnel training. Failure to comply with these requirements can result in monetary penalties as well as non-monetary sanctions. Monetary penalties vary based on an assigned risk factor for each potential violation, the severity of the violation and various other circumstances, such as whether the violation was intentional or concealed, whether there are repeated violations, the degree of the violator’s cooperation in investigating and remediating the violation and the presence of a compliance program, and such penalties can be substantial. Non-monetary sanctions include potential limitations on the violator’s activities or


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operation and placing the violator on a watchlist for major violators. Despite our best efforts to comply and the implementation of a compliance program intended to ensure reliability, there can be no assurance that violations will not occur that would result in material penalties or sanctions. If any of our subsidiaries were to violate the NERC reliability standards, even unintentionally, in any material way, any penalties or sanctions imposed against us could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Certain of our subsidiaries are also subject to requirements under Sections 203 and 205 of the FPA for approval of transactions; reporting, recordkeeping and accounting requirements; and for filing contracts related to the provision of jurisdictional services. Under FERC policy, failure to file jurisdictional agreements on a timely basis may result in foregoing the time value of revenues collected under the agreement, but not to the point where a loss would be incurred. The failure to obtain timely approval of transactions subject to FPA Section 203, or to comply with applicable reporting, recordkeeping or accounting requirements under FPA Section 205, could subject us to penalties that could have a material adverse effect on our financial condition, results of operations and cash flows.
Acts of war, terrorist attacks, cyber attacks, natural disasters, severe weather and other catastrophic events may have a material adverse effect on our business, financial condition, results of operations and cash flows.
Acts of war, terrorist attacks, cyber attacks, natural disasters, severe weather and other catastrophic events may negatively affect our business, financial condition and cash flows in unpredictable ways, such as increased security measures and disruptions of markets. Energy related assets, including, for example, our transmission facilities and DTE Electric’s, Consumers Energy’s and IP&L’s generation and distribution facilities that we interconnect with, may be at risk of acts of war, terrorist attacks and cyber attacks, as well as natural disasters, severe weather and other catastrophic events. In addition to any physical damage caused by such events, cyber attacks targeting our information systems could impair our records, networks, systems and programs, or transmit viruses to other systems. Such events or the threat of such events may increase costs associated with heightened security requirements. In addition, such events or threats may have a material effect on the economy in general and could result in a decline in energy consumption, which may have a material adverse effect on our business, financial condition, results of operations and cash flows.
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 pay dividends and fulfill our other 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 pay dividends to our shareholders are dividends and other payments received by us from time to time from our subsidiaries, proceeds raised from the sale of our debt and equity 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 for the payment of dividends to ITC Holdings’ shareholders or otherwise. 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. While we currently intend to continue to pay quarterly dividends on our common stock, we have no obligation to do so. The payment of dividends is within the absolute discretion of our board of directors and will depend on, among other things, our results of operations, working capital requirements, capital expenditure requirements, financial condition, contractual restrictions, anticipated cash needs and other factors that our board of directors deems relevant.

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. This financing strategy can have several important consequences, including, but not limited to, the following:


20


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 and, therefore, may pose substantial risk to our shareholders. A substantial portion of the dividends and payments in lieu of taxes we receive from our subsidiaries will be dedicated to the payment of interest on our indebtedness, thereby, reducing the funds available for working capital, capital expenditures and the payment of dividends on our common stock.
In the event of bankruptcy, reorganization or liquidation, our senior or subordinated creditors and the senior or subordinated creditors of our subsidiaries will be entitled to payment in full prior to any distributions to the holders of shares of our common stock.
We currently have debt instruments outstanding with short-term maturities or relatively short remaining maturities. Our ability to secure additional financing prior to or after these facilities mature, if needed, may be substantially restricted by the existing level of our indebtedness and the restrictions contained in our debt instruments. Additionally, the interest rates at which we might secure additional financings may be higher than our currently outstanding debt instruments or higher than forecasted at any point in time, which could adversely affect our business, financial condition, results of operations and cash flows.
Market conditions could affect our access to capital markets, restrict our ability to secure financing to make the capital expenditures and investments and pay other expenses planned by us which could adversely affect our business, financial condition, cash flows and results of operations.
We may incur substantial additional indebtedness in the future. The incurrence of additional indebtedness would increase the risks described above.
Certain provisions in our debt instruments limit our financial and operating flexibility.
Our debt instruments on a consolidated basis, including senior notes, secured notes, first mortgage bonds, revolving 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.
Our debt instruments also require us to meet certain financial ratios, such as maintaining certain debt to capitalization ratios. Our ability to comply with these and other requirements and restrictions may be affected by changes in economic or business conditions, results of operations or other events beyond our control. A failure to comply with the obligations contained in any of our debt instruments could result in acceleration of related debt and the acceleration of debt under other instruments evidencing indebtedness that may contain cross-acceleration or cross-default provisions.
Adverse changes in our credit ratings may negatively affect us.
Our ability to access capital markets is important to our ability to operate our business. Increased scrutiny of the energy industry and the impact of regulation, as well as changes in our financial performance and unfavorable conditions in the capital markets could result in credit agencies reexamining our credit ratings. A downgrade in our credit ratings could restrict or discontinue our ability to access capital markets at attractive rates and increase our


21


borrowing costs. A rating downgrade could also increase the interest we pay on commercial paper and under our revolving and term loan credit agreements.
Provisions in our Articles of Incorporation and bylaws, Michigan corporate law and our debt agreements may impede efforts by our shareholders to change the direction or management of our company.
Our Articles of Incorporation and bylaws contain provisions that might enable our management to resist a proposed takeover. These provisions could discourage, delay or prevent a change of control or an acquisition at a price that our shareholders may find attractive. These provisions also may discourage proxy contests and make it more difficult for our shareholders to elect directors and take other corporate actions. The existence of these provisions could limit the price that investors are willing to pay in the future for shares of our common stock. These provisions include:
a restriction limiting market participants from voting or owning 5% or more of the outstanding shares of our capital stock;
a requirement that special meetings of our shareholders may be called only by our board of directors, the chairman of our board of directors, our president or the holders of 25% of the shares of our outstanding common stock;
advance notice requirements for shareholder proposals and nominations; and
the authority of our board to issue, without shareholder approval, common or preferred stock, including in connection with our implementation of any shareholders rights plan, or “poison pill.”
In addition, our revolving and term loan credit agreements provide that a change in a majority of ITC Holdings’ board of directors that is not approved by the current ITC Holdings’ directors or acquiring beneficial ownership of 35% or more of ITC Holdings outstanding common shares will constitute a default under those agreements.
Provisions in our Articles of Incorporation restrict market participants from voting or owning 5% or more of the outstanding shares of our capital stock.
Certain of our Regulated Operating Subsidiaries have been granted favorable rate treatment by the FERC based on their independence from market participants. The FERC defines a “market participant” to include any person or entity that, either directly or through an affiliate, sells or brokers electricity, or provides ancillary services to an RTO. An affiliate, for these purposes, includes any person or entity that directly or indirectly owns, controls or holds with the power to vote 5% or more of the outstanding voting securities of a market participant. To help ensure that we and our subsidiaries will remain independent of market participants, our Articles of Incorporation impose certain restrictions on the ownership and voting of shares of our capital stock by market participants. In particular, the Articles of Incorporation provide that we are restricted from issuing any shares of capital stock or recording any transfer of shares if the issuance or transfer would cause any market participant, either individually or together with members of its “group” (as defined in SEC beneficial ownership rules), to beneficially own 5% or more of any class or series of our capital stock. Additionally, if a market participant, together with its group members, acquires beneficial ownership of 5% or more of any series of the outstanding shares of our capital stock, such market participant or any shareholder who is a member of a group including a market participant will not be able to vote or direct or control the votes of shares representing 5% or more of any series of our outstanding capital stock. Finally, to the extent a market participant, together with its group members, acquires beneficial ownership of 5% or more of the outstanding shares of any series of our capital stock, our Articles of Incorporation allow our board of directors to redeem any shares of our capital stock so that, after giving effect to the redemption, the market participant, together with its group members, will cease to beneficially own 5% or more of that series of our outstanding capital stock.
Risks Related to the Merger
On February 9, 2016, we entered into the Merger Agreement pursuant to which, among other things, Merger Sub will merge with and into ITC Holdings, as a result of which ITC Holdings will become a subsidiary of FortisUS. In connection with the proposed Merger, we are subject to certain risks including, but not limited to, those set forth below. For additional information related to the Merger Agreement, please refer to Note 20 to the consolidated financial statements and to the Current Report on Form 8-K filed with the SEC on February 11, 2016. The foregoing description of the Merger Agreement is qualified in its entirety by reference to the full text of the Merger Agreement attached as Exhibit 2.1 to the February 11, 2016 Form 8-K.


22


Completion of the Merger is subject to various conditions which, if not satisfied, may cause the Merger not to be completed in a timely manner or at all.
The completion of the Merger is subject to certain conditions, including, among others, (i) approval by our shareholders of the Merger Agreement, (ii) approval by Fortis’ shareholders of the issuance of shares of Fortis common stock to be issued in the Merger, (iii) obtaining certain regulatory and federal approvals including, among others, those of the FERC, the Committee on Foreign Investment in the United States, the United States Federal Trade Commission/Department of Justice under the Hart-Scott-Rodino Antitrust Improvement Act, and various state utilities regulators, and (iv) the absence of legal restraints prohibiting the completion of the Merger. Governmental agencies may not approve the Merger, or may impose conditions to any such approval or require changes to the terms of the Merger. Any such conditions or changes could have the effect of delaying completion of the Merger, imposing costs on or limiting the revenues of the combined company following the Merger or otherwise reducing the anticipated benefits of the Merger. Each party’s obligation to consummate the Merger is also subject to the accuracy of the representations and warranties of the other party (subject to certain qualifications and exceptions) and the performance in all material respects of the other party’s covenants under the Merger Agreement, including, with respect to us, certain covenants regarding operation of our business prior to completion of the Merger. As a result of these conditions, we cannot provide assurance that the Merger will be completed on the terms or timeline currently contemplated, or at all.
We will continue to incur substantial transaction-related costs in connection with the Merger.
We have incurred significant legal, advisory and financial services fees in connection with our board of directors’ review of strategic alternatives and the process of negotiating and evaluating the terms of the Merger. We expect to continue to incur additional costs in connection with the satisfaction of the various conditions to closing, including seeking approval from our shareholders and from applicable regulatory agencies. Such costs may be material and could have a material adverse effect on our future results of operations, cash flows and financial condition.
The announcement and pendency of the Merger could adversely affect our business, results of operations and financial condition.
The announcement and pendency of the Merger could cause disruptions in and create uncertainty surrounding our business, including affecting our relationships with our existing and future customers, suppliers and employees, which could have an adverse effect on our business, results of operations and financial condition, regardless of whether the Merger is completed. In particular, we could potentially lose important personnel as a result of the departure of employees who decide to pursue other opportunities in light of the Merger. We could also potentially lose customers or suppliers, and new customer or supplier contracts could be delayed or decreased. In addition, we have expended, and continue to expend, significant management resources in an effort to complete the Merger, which are being diverted from our day-to-day operations.
If the Merger is not completed, our stock price will likely fall to the extent that the current market price of our common stock reflects an assumption that a transaction will be completed. In addition, the failure to complete the Merger may result in negative publicity and/or a negative impression of us in the investment community and may affect our relationship with employees, customers and other partners in the business community.
While the Merger Agreement is in effect, we are subject to restrictions on our business activities.
Under the Merger Agreement, we are subject to certain restrictions on the conduct of our business and generally must operate our business in the ordinary course in all material respects prior to completing the Merger unless we obtain the consent of FortisUS, which may restrict our ability to exercise certain of our business strategies. These restrictions may prevent us from pursuing otherwise attractive business opportunities, making certain investments or acquisitions, selling assets, engaging in capital expenditures in excess of certain agreed limits, incurring indebtedness or making changes to our business prior to the completion of the Merger or termination of the Merger Agreement. These restrictions could have an adverse effect on our business, financial condition and results of operations.
In addition, the Merger Agreement prohibits us from (i) soliciting or, subject to certain exceptions set forth in the Merger Agreement, knowingly facilitating or encouraging any inquiry or proposal relating to alternative business combination transactions, or (ii) subject to certain exceptions set forth in the Merger Agreement, engaging in discussions or negotiations regarding, or providing any nonpublic information in connection with, proposals relating to alternative business combination transactions. The Merger Agreement also requires us to pay FortisUS a


23


termination fee of $245 million if the Merger Agreement is terminated under certain circumstances, including if we terminate the Merger Agreement to enter into an agreement that provides for a Superior Proposal (as defined in the Merger Agreement) or if our board of directors fails to recommend the Merger Agreement to shareholders. These provisions limit our ability to pursue offers from third parties that could result in greater value to our shareholders than the value resulting from the Merger. The termination fee may also discourage third parties from pursuing an alternative acquisition proposal with respect to us.
Because the market value of Fortis common stock that our shareholders will receive in the Merger may fluctuate, our shareholders cannot be sure of the market value of the stock portion of the consideration that they will receive in the Merger.
The stock portion of the merger consideration that our shareholders will receive is a fixed number of shares of Fortis common stock, not a number of shares that will be determined based on a fixed market value. The market value of Fortis common stock, the exchange rate between the Canadian dollar and U.S. dollar and our common stock at the effective time of the Merger may vary significantly from their respective values on the date that the Merger Agreement was executed or at other dates, such as the date on which our shareholders vote on the approval of the Merger Agreement and the effective date of the Merger. Stock price changes may result from a variety of factors, including changes in Fortis’ or ITC Holdings’ respective businesses, operations or prospects, regulatory considerations, and general business, market, industry or economic conditions. The exchange ratio relating to the stock portion of the Merger Consideration will not be adjusted to reflect any changes in the market value of Fortis common stock, the comparative value of the Canadian dollar and U.S. dollar or our common stock except in very limited circumstances.
If the Merger is completed, the combined company may not be able to successfully integrate our business with Fortis and therefore may not be able to realize the anticipated benefits of the Merger.
Because a portion of the merger consideration consists of Fortis common stock, realization of the anticipated benefits in the Merger will depend, in part, on the combined company’s ability to successfully integrate our business with Fortis. The combined company will be required to devote significant management attention and resources to integrating its business practices and support functions. The diversion of management’s attention and any delays or difficulties encountered in connection with the Merger and the integration of the two companies’ operations could have an adverse effect on the business, financial results, financial condition or stock price of Fortis (as the combined company following the Merger). The integration process may also result in additional and unforeseen expenses. There can be no assurance that the contemplated synergies anticipated from the Merger will be realized.
After the completion of the Merger, sales of Fortis common stock may negatively affect its market price.
The shares of Fortis common stock to be issued in the Merger to our shareholders will generally be eligible for immediate resale. The market price of Fortis common stock could decline as a result of sales of a large number of shares of Fortis common stock in the market after the completion of the Merger or the perception in the market that these sales could occur.
We may be the target of securities class action and derivative lawsuits which could result in substantial costs and may delay or prevent the Merger from being completed.
Securities class action lawsuits and derivative lawsuits are often brought against companies that have entered into merger agreements. Even if the lawsuits are without merit, defending against these claims can result in substantial costs to us and divert management time and resources. Additionally, if a plaintiff is successful in obtaining an injunction prohibiting consummation of the Merger, then that injunction may delay or prevent the Merger from being completed.
ITEM 1B.     UNRESOLVED STAFF COMMENTS.
None.
ITEM 2.    PROPERTIES.
Our Regulated Operating Subsidiaries’ transmission facilities are located in Michigan’s Lower Peninsula and portions of Iowa, Minnesota, Illinois, Missouri, Kansas and Oklahoma. Our MISO Regulated Operating Subsidiaries have agreements with other utilities for the joint ownership of specific substations and transmission lines. See Note 15 to the consolidated financial statements.


24


ITCTransmission owns the assets of a transmission system and related assets, including:
approximately 3,100 circuit miles of overhead and underground transmission lines rated at voltages of 120 kV to 345 kV;
approximately 18,700 transmission towers and poles;
station assets, such as transformers and circuit breakers, at 182 stations and substations which either interconnect ITCTransmission’s transmission facilities or connect ITCTransmission’s facilities with generation or distribution facilities owned by others;
other transmission equipment necessary to safely operate the system (e.g., monitoring and metering equipment);
warehouses and related equipment;
associated land held in fee, rights-of-way and easements;
an approximately 188,000 square-foot corporate headquarters facility and operations control room in Novi, Michigan, including furniture, fixtures and office equipment; and
an approximately 40,000 square-foot facility in Ann Arbor, Michigan that includes a back-up operations control room.
ITCTransmission’s First Mortgage Bonds are issued under ITCTransmission’s first mortgage and deed of trust. As a result, the bondholders have the benefit of a first mortgage lien on substantially all of ITCTransmission’s property.
METC owns the assets of a transmission system and related assets, including:
approximately 5,600 circuit miles of overhead transmission lines rated at voltages of 120 kV to 345 kV;
approximately 36,900 transmission towers and poles;
station assets, such as transformers and circuit breakers, at 101 stations and substations which either interconnect METC’s transmission facilities or connect METC’s facilities with generation or distribution facilities owned by others;
other transmission equipment necessary to safely operate the system (e.g., monitoring and metering equipment); and
warehouses and related equipment.

METC's Senior Secured Notes are issued under METC's first mortgage indenture. As a result, the noteholders have the benefit of a first mortgage lien on substantially all of METC's property.
METC does not own the majority of the land on which its assets are located, but under the provisions of its Easement Agreement with Consumers Energy, METC has an easement to use the land, rights-of-way, leases and licenses in the land on which its transmission lines are located that are held or controlled by Consumers Energy. See “Item 1 Business — Operating Contracts — METC — Amended and Restated Easement Agreement.”
ITC Midwest owns the assets of a transmission system and related assets, including:
approximately 6,600 circuit miles of transmission lines rated at voltages of 34.5 kV to 345 kV;
transmission towers and poles;
station assets, such as transformers and circuit breakers, at approximately 273 stations and substations which either interconnect ITC Midwest’s transmission facilities or connect ITC Midwest’s facilities with generation or distribution facilities owned by others;
other transmission equipment necessary to safely operate the system (e.g., monitoring and metering equipment);
warehouses and related equipment; and
associated land held in fee, rights-of-way and easements.


25


ITC Midwest’s First Mortgage Bonds are issued under ITC Midwest’s first mortgage and deed of trust. As a result, the bondholders have the benefit of a first mortgage lien on substantially all of ITC Midwest’s property.
ITC Great Plains owns transmission and related assets including:
approximately 440 miles of transmission lines rated at a voltage of 345 kV;
approximately 1,910 transmission towers and poles;
station assets, such as transformers and circuit breakers, at 8 stations and substations which either interconnect ITC Great Plains’ transmission facilities or connect ITC Great Plains’ facilities with transmission, generation or distribution facilities owned by others;
other transmission equipment necessary to safely operate the system (e.g., monitoring and metering equipment); and
associated land held in fee, rights-of-way and easements.
ITC Great Plains’ First Mortgage Bonds are issued under ITC Great Plains’ first mortgage and deed of trust. As a result, the bondholders have the benefit of a first mortgage lien on substantially all of ITC Great Plains’ property.
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 4 and 16 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.


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PART II
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
Stock Price and Dividends
Our common stock is traded on the NYSE, under the ticker symbol “ITC”. As of February 19, 2016, there were approximately 826 shareholders of record of our common stock.
The following tables set forth the high and low sales price per share of the common stock for each full quarterly period in 2015 and 2014, as reported on the NYSE, and the cash dividends per share paid during the periods indicated.
Year Ended December 31, 2015
 
High
 
Low
 
Dividends
Quarter ended December 31, 2015
 
$
39.60

 
$
30.33

 
$
0.1875

Quarter ended September 30, 2015
 
35.68

 
31.16

 
0.1875

Quarter ended June 30, 2015
 
37.12

 
30.64

 
0.1625

Quarter ended March 31, 2015
 
44.00

 
35.54

 
0.1625

 
 
 
 
 
 
 
Year Ended December 31, 2014
 
High
 
Low
 
Dividends
Quarter ended December 31, 2014
 
$
42.01

 
$
34.05

 
$
0.1625

Quarter ended September 30, 2014
 
38.14

 
34.60

 
0.1625

Quarter ended June 30, 2014
 
38.43

 
34.26

 
0.1425

Quarter ended March 31, 2014
 
37.41

 
31.18

 
0.1425

The declaration and payment of dividends is subject to the discretion of ITC Holdings’ board of directors and depends on various factors, including our net income, financial condition, cash requirements, future prospects and other factors deemed relevant by ITC Holdings’ board of directors. As a holding company with no business operations, ITC Holdings’ material assets consist primarily of the common stock or ownership interests in its subsidiaries. ITC Holdings’ material cash inflows are only from dividends and other payments received from time to time from its subsidiaries, proceeds raised from the sale of debt and equity securities, issuances under its commercial paper program and borrowings under its revolving credit agreement. ITC Holdings may not be able to access cash generated by its subsidiaries in order to pay dividends to shareholders. The ability of ITC Holdings’ subsidiaries to make dividend and other payments to ITC Holdings is subject to the availability of funds after considering the subsidiaries’ funding requirements and the terms of their indebtedness, the regulations of the FERC under FPA and applicable state laws. The debt agreements to which we are a party contain numerous financial covenants that could limit ITC Holdings’ ability to pay dividends, as well as covenants that prohibit ITC Holdings from paying dividends if in default under its term loan credit agreement. Further, each of our subsidiaries is legally distinct from ITC Holdings and has no obligation, contingent or otherwise, to make funds available to ITC Holdings.
The board of directors intends to increase the dividend rate from time to time as necessary to maintain an appropriate dividend payout ratio, subject to prevailing business conditions, applicable restrictions on dividend payments, the availability of capital resources and our investment opportunities.
See discussion in Note 20 to the consolidated financial statements regarding certain restrictions on our ability to pay dividends related to the Merger.
The transfer agent for the common stock is Computershare Trust Company, N.A., P.O. Box 43078 Providence, RI 02940-3078.
In addition, the information contained in the Equity Compensation table under “Item 12 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” of this report is incorporated herein by reference.


27


Stock Repurchases
The following table sets forth, the repurchases of common stock for the quarter ended December 31, 2015:
Period
 
 Total Number of
Shares Purchased (1)
 
 Average Price
Paid per Share
 
Total Number of
Shares Purchased as
Part of Publicly
Announced Plan or Program (2)
 
Maximum Number (or
Approximate Dollar
Value) of Shares that May
Yet Be Purchased Under the Plans or Programs (in millions) (2)
 
 
 
 
October 2015
 
2,053

 
$
32.55

 

 
$
28.0

November 2015
 
771,806

 
32.57

 
771,299

 
5.0

December 2015
 
1,053

 
37.83

 

 

Total
 
774,912

 
$
32.58

 
771,299

 


____________________________
(1)
Shares purchased other than those purchased as part of a publicly announced plan were delivered to us by employees as payment of tax withholding obligations due upon the vesting of restricted stock.
(2)
In April 2014, the board of directors authorized and ITC Holdings announced a share repurchase program for up to $250.0 million, which expired on December 31, 2015. Pursuant to the April 2014 authorization, on September 30, 2015, ITC Holdings entered into an accelerated share repurchase agreement (the “2015 ASR Program”) with Barclays for $115.0 million, under which ITC Holdings paid $115.0 million to Barclays on September 30, 2015 and received an initial delivery of 2.8 million shares on October 1, 2015, with a fair market value of $92.0 million. The 2015 ASR Program was settled on November 5, 2015 and ITC Holdings received an additional 0.8 million shares as determined by the volume-weighted average share price during the term of the 2015 ASR Program, less an agreed upon discount and adjusted for the initial share delivery. See Note 13 to the consolidated financial statements for further discussion on the 2015 ASR Program.


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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 thousands, except per share data)
2015
 
2014
 
2013
 
2012
 
2011
OPERATING REVENUES (a) (b) (c)
$
1,044,768

 
$
1,023,048

 
$
941,272

 
$
830,535

 
$
757,397

OPERATING EXPENSES
 
 
 
 
 
 
 
 
 
Operation and maintenance
113,123

 
111,623

 
112,821

 
121,941

 
129,288

General and administrative (d) (e)
144,919

 
115,031

 
149,109

 
112,091

 
82,790

Depreciation and amortization
144,672

 
128,036

 
118,596

 
106,512

 
94,981

Taxes other than income taxes
82,354

 
76,534

 
65,824

 
59,701

 
53,430

Other operating income and expense — net
(1,017
)
 
(1,005
)
 
(1,139
)
 
(769
)
 
(844
)
Total operating expenses
484,051

 
430,219

 
445,211

 
399,476

 
359,645

OPERATING INCOME
560,717

 
592,829

 
496,061

 
431,059

 
397,752

OTHER EXPENSES (INCOME)
 
 
 
 
 
 
 
 
 
Interest expense — net
203,779

 
186,636

 
168,319

 
155,734

 
146,936

Allowance for equity funds used during construction
(28,075
)
 
(20,825
)
 
(30,159
)
 
(23,000
)
 
(16,699
)
Loss on extinguishment of debt

 
29,205

 

 

 

Other income
(2,071
)
 
(1,103
)
 
(1,038
)
 
(2,401
)
 
(2,881
)
Other expense
3,207

 
4,511

 
6,571

 
4,218

 
3,962

Total other expenses (income)
176,840

 
198,424

 
143,693

 
134,551

 
131,318

INCOME BEFORE INCOME TAXES
383,877

 
394,405

 
352,368

 
296,508

 
266,434

INCOME TAX PROVISION
141,471

 
150,322

 
118,862

 
108,632

 
94,749

NET INCOME
$
242,406

 
$
244,083

 
$
233,506

 
$
187,876

 
$
171,685

 
 
 
 
 
 
 
 
 
 
Basic earnings per common share (f)
$
1.57

 
$
1.56

 
$
1.49

 
$
1.22

 
$
1.12

Diluted earnings per common share (f)
$
1.56

 
$
1.54

 
$
1.47

 
$
1.20

 
$
1.10

Dividends declared per common share (f)
$
0.700

 
$
0.610

 
$
0.535

 
$
0.487

 
$
0.458

 
ITC Holdings and Subsidiaries
 
As of December 31,
(In thousands)
2015
 
2014
 
2013
 
2012
 
2011
BALANCE SHEET DATA:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
13,859

 
$
27,741

 
$
34,275

 
$
26,187

 
$
58,344

Working capital (deficit) (g)
(549,911
)
 
(290,709
)
 
(325,066
)
 
(828,099
)
 
(134,575
)
Property, plant and equipment — net
6,109,639

 
5,496,875

 
4,846,526

 
4,134,579

 
3,415,823

Goodwill
950,163

 
950,163

 
950,163

 
950,163

 
950,163

Total assets (g)
7,582,122

 
6,959,578

 
6,265,018

 
5,541,795

 
4,802,730

Debt:
 
 
 
 
 
 
 
 
 
ITC Holdings
2,314,967

 
2,135,244

 
1,881,918

 
1,689,619

 
1,459,599

Regulated Operating Subsidiaries
2,141,290

 
1,968,342

 
1,730,194

 
1,457,608

 
1,185,423

Total debt
4,456,257

 
4,103,586

 
3,612,112

 
3,147,227

 
2,645,022

Total stockholders’ equity
$
1,709,071

 
$
1,669,557

 
$
1,613,732

 
$
1,414,855

 
$
1,258,892

 
ITC Holdings and Subsidiaries
 
Year Ended December 31,
(In thousands)
2015
 
2014
 
2013
 
2012
 
2011
CASH FLOWS DATA:
 
 
 
 
 
 
 
 
 
Expenditures for property, plant and equipment
$
684,140

 
$
733,145

 
$
821,588

 
$
802,763

 
$
556,931



29


____________________________
(a)
During 2015 and 2014, we recognized an aggregate estimated regulatory liability for the potential refund relating to the rate of return on equity complaints as described in Note 16 to the consolidated financial statements, which resulted in a reduction in operating revenues of $115.1 million and $46.9 million, respectively.
(b)
During 2015, we recognized a regulatory liability for the refund relating to the formula rate template modifications filing as described in Note 4 to the consolidated financial statements, which resulted in a reduction in operating revenues of $9.5 million.
(c)
During 2012, we initially recognized the FERC audit refund liability, which resulted in a reduction in operating revenues of $11.0 million.
(d)
The increase in general and administrative expenses in 2015 were due primarily to higher compensation related expenses, including the development bonuses described below under “Capital Project Updates and Other Recent Developments — Development Bonuses,” and higher legal and advisory professional service fees for various development initiatives.
(e)
During 2014, 2013, 2012 and 2011, we expensed external legal, advisory and financial services fees of $0.4 million, $43.1 million, $19.4 million and $7.0 million, respectively, relating to the Entergy Transaction recorded within general and administrative expenses as discussed in Note 17 to the consolidated financial statements.
(f)
Per share data reflect the three-for-one stock split that occurred on February 28, 2014. See further discussion on the stock split in Note 13 to the consolidated financial statements.
(g)
All amounts presented reflect the change in the authoritative guidance on the presentation of deferred income taxes on the balance sheet. Refer to Notes 3 and 10 of the consolidated financial statements for more information.
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
Safe Harbor Statement Under The Private Securities Litigation Reform Act of 1995
Our reports, filings and other public announcements contain certain statements that describe our management’s beliefs concerning future business conditions, plans and prospects, growth opportunities, the outlook for our business and the electric transmission industry and the proposed Merger with Fortis based upon information currently available. Such statements are “forward-looking” statements within the meaning of the Private Securities Litigation Reform Act of 1995. Wherever possible, we have identified these forward-looking statements by words such as “will,” “may,” “anticipates,” “believes,” “intends,” “estimates,” “expects,” “projects,” “likely” and similar phrases. These forward-looking statements are based upon assumptions our management believes are reasonable. Such forward-looking statements are based on estimates and assumptions and subject to significant risks and uncertainties which could cause our actual results, performance and achievements to differ materially from those expressed in, or implied by, these statements, including, among others, the risks and uncertainties listed in this report under “Item 1A Risk Factors” and in our other reports filed with the SEC from time to time.
Forward-looking statements speak only as of the date made and can be affected by assumptions we might make or by known or unknown risks and uncertainties. Many factors mentioned in our discussion in this report will be important in determining future results. Consequently, we cannot assure you that our expectations or forecasts expressed in such forward-looking statements will be achieved. Except as required by law, we undertake no obligation to publicly update any of our forward-looking or other statements, whether as a result of new information, future events or otherwise.
Overview
Through our Regulated Operating Subsidiaries, we operate high-voltage systems in Michigan’s Lower Peninsula and portions of Iowa, Minnesota, Illinois, Missouri, Kansas and Oklahoma that transmit electricity from generating stations to local distribution facilities connected to our systems. Our business strategy is to operate, maintain and invest in transmission infrastructure in order to enhance system integrity and reliability, reduce transmission constraints and upgrade the transmission networks to support new generating resources interconnecting to our transmission systems. We also are pursuing development projects not within our existing systems, which are


30


likewise intended to improve overall grid reliability, reduce transmission constraints and facilitate interconnections of new generating resources, as well as enhance competitive wholesale electricity markets.
As electric transmission utilities with rates regulated by the FERC, our Regulated Operating Subsidiaries earn revenues through tariff rates charged for the use of their electric transmission systems by our customers, which include investor-owned utilities, municipalities, cooperatives, power marketers and alternative energy suppliers. As independent transmission companies, our Regulated Operating Subsidiaries are subject to rate regulation only by the FERC. The rates charged by our Regulated Operating Subsidiaries are established using cost-based formula rate templates, 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.”
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.
We derive nearly all of our revenues from providing electric transmission service over our Regulated Operating Subsidiaries’ transmission systems to investor-owned utilities, such as DTE Electric, Consumers Energy and IP&L, and other entities, such as alternative electricity suppliers, power marketers and other wholesale customers that provide electricity to end-use consumers as well as from transaction-based capacity reservations on our transmission systems.
Significant recent matters that influenced our financial position and results of operations and cash flows for the year ended December 31, 2015 or that may affect future results include:
Our capital investments of $767.2 million at our Regulated Operating Subsidiaries ($189.6 million, $174.8 million, $388.4 million and $14.4 million at ITCTransmission, METC, ITC Midwest and ITC Great Plains, respectively) during the year ended December 31, 2015, resulting primarily from our focus on improving system reliability, increasing system capacity and upgrading the transmission network to support new generating resources;
Debt issuances as described in Note 8 to the consolidated financial statements and borrowings under our revolving and term loan credit agreements in 2015 and 2014 to fund capital investment at our Regulated Operating Subsidiaries and for general corporate purposes, resulting in higher interest expense;
Debt maturing within one year and the potentially higher interest rates associated with the additional financing required to repay this debt as discussed in Note 8 to the consolidated financial statements;
Establishment of a commercial paper program as described in Note 8 to the consolidated financial statements, which provides an additional source of liquidity for our working capital needs;
Recognition of the refund liabilities in 2015 and 2014 for the refund relating to the formula rate template modifications filing and the potential refund relating to the rate of return on equity complaints (“ROE complaints”) described in Notes 4 and 16 to the consolidated financial statements, respectively, which resulted in an estimated after-tax reduction to net income of $79.4 million and $28.9 million for the years ended December 31, 2015 and 2014, respectively;
Recognition of the contingent liability, including interest, relating to the Michigan sales and use tax audit of ITCTransmission as described in Note 16 to the consolidated financial statements, which primarily resulted in an increase to property, plant and equipment; and
Repurchases of common stock of $115.0 million and $130.0 million during 2015 and 2014, respectively, under accelerated share repurchase agreements as described in Note 13 to the consolidated financial statements.
These items are discussed in more detail throughout “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
On February 9, 2016, we entered into the Merger Agreement with Fortis, FortisUS and Merger Sub. We expect the total fees and costs related to the Merger will be material to our results of operations in 2016. For further explanation, refer to Note 20 to the consolidated financial statements. The discussion below excludes any impact that may result from the Merger.


31


Cost-Based Formula Rates with True-Up Mechanism
Our Regulated Operating Subsidiaries calculate their revenue requirements using cost-based formula rate templates and are effective without the need to file rate cases with the FERC, although the rates are subject to legal challenge at the FERC. Under their cost-based formula rate templates, 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 rate templates, our Regulated Operating Subsidiaries recover expenses and earn a return on and recover investments in property, plant and equipment on a current basis, rather than lagging. The formula rate templates for a given year initially utilize 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 cost-based formula rate templates 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.
Illustration of Formula Rate Setting
Line
Item
Instructions
Amount
1
Rate base (a)
 
$
1,000,000

2
Multiply by 13-month weighted average cost of capital (b)
 
9.43
%
3
Allowed return on rate base
(Line 1 x Line 2)
$
94,300

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

5
Income taxes
 
50,000

6
Gross revenue requirement
(Line 3 + Line 4 + Line 5)
$
294,300

____________________________
(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 as follows:
 
 
 
 
 
Weighted
 
 
 
 
 
Average
 
Percentage of
 
 
 
Cost of
 
Total Capitalization
 
Cost of Capital
 
Capital
Debt
40.00%
 
5.00% =
 
2.00
%
Equity
60.00%
 
12.38% =
 
7.43
%
 
100.00%
 
 
 
9.43
%
Revenue Accruals and Deferrals — Effects of Monthly Peak Loads
For our MISO Regulated Operating Subsidiaries, monthly peak loads are used for billing network revenues, which currently is the largest component of our operating revenues. One of the primary factors that impacts the revenue accruals and deferrals at our MISO Regulated Operating Subsidiaries is actual monthly peak loads experienced as compared to those forecasted in establishing the annual network transmission rate. Under their cost-based formula rates that contain a true-up mechanism, our Regulated Operating Subsidiaries accrue or defer revenues to the extent that their actual revenue requirement for the reporting period is higher or lower, respectively,


32


than the amounts billed relating to that reporting period. Although monthly peak loads do not impact operating revenues recognized, network load affects the timing of our cash flows from transmission service. The monthly peak load of our MISO Regulated Operating Subsidiaries is generally impacted by weather and economic conditions and seasonally shaped with higher load in the summer months when cooling demand is higher.
ITC Great Plains does not receive revenue based on a peak load or a dollar amount per kW each month and, therefore, peak load does not have a seasonal effect on operating cash flows. The SPP tariff applicable to ITC Great Plains is billed ratably each month based on its annual projected revenue requirement posted annually by SPP.
Capital Investment and Operating Results Trends
We expect a long-term upward trend in revenues and earnings, subject to the impact of any rate changes and required refunds as a result of the resolution of the ROE complaints as described in Note 16 to the consolidated financial statements. The primary factor that is expected to continue to increase our revenues and earnings in future years is increased rate base that would result from our anticipated capital investment, in excess of depreciation, from our Regulated Operating Subsidiaries’ long-term capital investment programs to improve reliability, increase system capacity and upgrade the transmission network to support new generating resources. In addition, our capital investment efforts relating to development initiatives are based on establishing an ongoing pipeline of projects that would position us for long-term growth. Investments in property, plant and equipment, when placed in-service upon completion of a capital project, are added to the rate base of our Regulated Operating Subsidiaries.
Our Regulated Operating Subsidiaries strive for high reliability of their systems and improvement in system accessibility for all generation resources. The FERC requires compliance with certain reliability standards and may take enforcement actions against violators, including the imposition of substantial fines. NERC is responsible for developing and enforcing these mandatory reliability standards. We continually assess our transmission systems against standards established by NERC, as well as the standards of applicable regional entities under NERC that have been delegated certain authority for the purpose of proposing and enforcing reliability standards. We believe that we meet the applicable standards in all material respects, although further investment in our transmission systems and an increase in maintenance activities will likely be needed to maintain compliance, improve reliability and address any new standards that may be promulgated.
We also assess our transmission systems against our own planning criteria that are filed annually with the FERC. Based on our planning studies, we see needs to make capital investments to (1) rebuild existing property, plant and equipment; (2) upgrade the system to address demographic changes that have impacted transmission load and the changing role that transmission plays in meeting the needs of the wholesale market, including accommodating the siting of new generation or increasing import capacity to meet changes in peak electrical demand; (3) relieve congestion in the transmission systems; and (4) achieve state and federal policy goals, such as renewable generation portfolio standards.
During the year ended December 31, 2015, we made capital investments of $767.2 million at our Regulated Operating Subsidiaries (in amounts of $189.6 million, $174.8 million, $388.4 million and $14.4 million at ITCTransmission, METC, ITC Midwest and ITC Great Plains, respectively). The following table shows our actual and expected capital investments at our Regulated Operating Subsidiaries:
 
 
 
 
 
 
Forecasted
 
 
 
 
Actual Capital Investment
 
Capital
 
Total Capital
 
 
Year Ended December 31,
 
Investment
 
Investment
Source of Investment
 
2014 (a)
 
2015 (a)
 
2016 — 2018
 
2014 — 2018
(In millions)
 
 
 
 
 
 
 
 
Current Transmission Systems
 
$
468.1

 
$
569.1

 
$
1,523

 
$
2,560

Regional Infrastructure
 
325.4

 
198.1

 
530

 
1,054

Total Regulated Operating Subsidiaries
 
$
793.5

 
$
767.2

 
$
2,053

 
$
3,614

____________________________
(a)
Capital investment amounts differ from cash expenditures for property, plant and equipment included in our consolidated statements of cash flows due in part to differences in construction costs incurred compared to cash paid during that period, as well as payments for major equipment inventory that are included in cash


33


expenditures, but not included in capital investment until transferred to construction work in progress, among other factors.
Refer to “Item 1 Business — Development of Business — Development Projects” for discussion of our development projects. We are pursuing projects that could result in a significant amount of capital investment, but are not able to estimate the amounts we ultimately expect to achieve or the timing of such investments. During the year ended December 31, 2015 and 2014, we made capital investments of $4.2 million and $0.5 million, respectively, relating to development activities.
Investments in property, plant and equipment could vary due to, among other things, the impact of actual loads, forecasted loads, regional economic conditions, weather conditions, union strikes, labor shortages, material and equipment prices and availability, our ability to obtain any necessary financing for such expenditures, limitations on the amount of construction that can be undertaken on our systems at any one time, regulatory approvals for reasons relating to rate construct, environmental, siting, regional planning, cost recovery or other issues or as a result of legal proceedings, variances between estimated and actual costs of construction contracts awarded and the potential for greater competition for new development projects. In addition, investments in transmission network upgrades for generator interconnection projects could change from prior estimates significantly due to changes in the MISO queue for generation projects and other factors beyond our control.
Capital Project Updates and Other Recent Developments
Thumb Loop Project
The Thumb Loop Project, constructed by ITCTransmission, consists of a 140-mile, double-circuit 345 kV transmission line and related substations that will serve as the backbone of the transmission system needed to accommodate future wind development projects in the Michigan counties of Tuscola, Huron, Sanilac and St. Clair. The final phase of the Thumb Loop Project was placed in-service in May 2015. Through December 31, 2015, ITCTransmission has invested $501.4 million in the Thumb Loop Project and any further investment to complete this project is not expected to be material.
ITC Great Plains
ITC Great Plains made a filing with the FERC, under Section 205 of the FPA, in May 2013 to recover start-up, development and pre-construction expenses, including associated debt and equity carrying charges, in future rates as discussed in Note 4 of the consolidated financial statements. These expenses included certain costs incurred by ITC Great Plains for the Kansas Electric Transmission Authority Project (placed in service in 2012) and the Kansas V-Plan Project (placed in service in 2014) prior to their construction. On March 26, 2015, FERC accepted ITC Great Plains’ request to commence amortization of the authorized regulatory assets, subject to refund, as well as set the matter for hearing and settlement judge procedures. During the third quarter of 2015, ITC Great Plains and the settling parties reached an uncontested settlement agreement, which was certified by the presiding administrative law judge, but remained subject to acceptance by FERC. On December 18, 2015, the FERC issued an order accepting the uncontested settlement agreement, which authorized ITC Great Plains to recover $24.4 million of these expenses and associated carrying costs, including the equity component not recognized under accounting principles generally accepted in the United States of America (“GAAP”). See Note 4 to the consolidated financial statements for additional detail on these ITC Great Plains regulatory assets.
North Central Region Development
In December 2011, MISO approved a portfolio of MVPs which includes portions of four MVPs that we will construct, own and operate. The four MVPs are located in south central Minnesota, northern and southeast Iowa, southwest Wisconsin, and northeast Missouri and are in various stages of construction and included in ITC Midwest’s capital investment amounts. We currently estimate ITC Midwest will invest approximately $500 million in the four MVPs from 2016 through 2018.
Development Bonuses
During 2015, 2014 and 2013, we recognized general and administrative expenses of $10.5 million, $2.7 million and $3.4 million, respectively, for bonuses for certain development projects, including the successful completion of certain milestones relating to projects at ITC Great Plains. It is reasonably possible that future development-related bonuses may be authorized and awarded for other development projects.


34


Rate of Return on Equity and Capital Structure Complaints
On November 12, 2013, certain parties filed a joint complaint with the FERC under Section 206 of the FPA (the “Initial Complaint”), requesting that the FERC find the current 12.38% MISO regional base ROE rate (the “base ROE”) for all MISO TOs, including ITCTransmission, METC and ITC Midwest to no longer be just and reasonable. The complainants sought a FERC order reducing the base ROE used in our MISO Regulated Operating Subsidiaries’ formula transmission rates to 9.15%, reducing the equity component of our capital structure from the FERC approved 60% to 50% and terminating the ROE adders currently approved for certain ITC Holdings operating companies, including adders currently utilized by ITCTransmission and METC.
We believe that the current ROE encourages transmission investment and offsets the burdens associated with maintaining the independent transmission business model and RTO membership. ITCTransmission, METC and ITC Midwest filed responses during the first quarter of 2014, separately and together with other MISO TOs, that sought dismissal of the Initial Complaint for its failure to satisfy the requirements of FPA Section 206 and the FERC’s accompanying Rules, or denial of the Initial Complaint on the merits, with prejudice.
On October 16, 2014, FERC granted the complainants’ request in part by setting the base ROE for hearing and settlement procedures, while denying all other aspects of the Initial Complaint. FERC found that the complainants failed to show that the use of actual or FERC-approved capital structures that include more than 50% equity is unjust and unreasonable. FERC also denied the request to terminate ITCTransmission’s and METC’s ROE incentives. The order reiterated that any TO’s total ROE rate is limited by the top end of a zone of reasonableness and the TO’s ability to implement the full amount of previously granted ROE adders may be affected by the outcome of the hearing. FERC set the refund effective date as November 12, 2013.
During the fourth quarter of 2014, the MISO TOs engaged in the ordered FERC settlement procedures with the complainants, but were not able to reach resolution. On January 5, 2015, the Chief Judge of FERC issued an order which terminated settlement procedures and set the matter for hearing, with an initial decision due within 47 weeks of the order. On April 6, 2015, the MISO TOs filed expert witness testimony in the Initial Complaint proceeding supporting the existing base ROE as just and reasonable. However, in the event that FERC elects to change the base ROE, the testimony included a recommendation of 11.39% base ROE for the period of November 12, 2013 through February 11, 2015 (the “Initial Refund Period”). On December 22, 2015, the presiding administrative law judge issued an initial decision on the Initial Complaint, which recommends a base ROE of 10.32% for the Initial Refund Period, with a maximum ROE of 11.35%. The initial decision is a non-binding recommendation to FERC on the Initial Complaint and may be contested by the MISO TOs and/or the complainants. In resolving the Initial Complaint, we expect FERC to establish a new base ROE to determine any potential refund liability for the Initial Refund Period. The new base ROE as well as any ROE adders, subject to the limitations of the top end of any zone of reasonableness that is established, are expected to be used to calculate the refund liability for the Initial Refund Period. We anticipate a FERC order on the Initial Complaint by the end of 2016.
On February 12, 2015, an additional complaint was filed with the FERC under Section 206 of the FPA (the “Second Complaint”) by separate complainants, seeking a FERC order to reduce the base ROE used in our MISO Regulated Operating Subsidiaries’ formula transmission rates to 8.67%, with an effective date of February 12, 2015. On March 11, 2015, the MISO TOs filed an answer to the Second Complaint with the FERC supporting the current base ROE as just and reasonable. On June 18, 2015, FERC accepted the Second Complaint and set it for hearing and settlement procedures. FERC also set the refund effective date for the Second Complaint as February 12, 2015.
On October 20, 2015, the MISO TOs filed expert witness testimony in the Second Complaint proceeding supporting the existing base ROE as just and reasonable. However, in the event that FERC elects to change the base ROE, the testimony included a recommendation of 10.75% base ROE for the period of February 12, 2015 through May 11, 2016 (the “Second Refund Period”). Updated data to be considered in establishing any new base ROE was filed by the parties to the Second Complaint in January 2016. In resolving the Second Complaint, we expect FERC to establish a new base ROE to determine any potential refund liability for the Second Refund Period. The base ROE established by FERC for the Second Complaint as well as any ROE adders, subject to the limitations of the top end of any zone of reasonableness established, are expected to be used to calculate the refund liability for the Second Refund Period. The initial decision on the Second Complaint is expected by June 30, 2016, with the related FERC order anticipated in 2017.


35


We believe it is probable that refunds will be required for these matters and as of December 31, 2015, the estimated range of refunds on a pre-tax basis is expected to be from $168.0 million to $212.4 million for the period from November 12, 2013 through December 31, 2015. As of December 31, 2015 and 2014, our MISO Regulated Operating Subsidiaries had recorded an aggregate estimated regulatory liability of $168.0 million and $47.8 million, respectively, representing the low end of the range of potential refunds as of those dates, as there is no best estimate within the range of refunds. The recognition of this estimated liability resulted in a reduction in revenues of $115.1 million and $46.9 million and an increase in interest expense of $5.1 million and $0.9 million for the years ended December 31, 2015 and 2014, respectively. This resulted in an estimated after-tax reduction to net income of $73.2 million and $28.9 million for the years ended December 31, 2015 and 2014, respectively. No amounts related to these complaints were recorded as of or for the year ended December 31, 2013.
Based on the estimated range of refunds identified above, we believe that it is reasonably possible that these matters could result in an additional estimated pre-tax refund of up to $44.4 million (or a $27.3 million estimated after-tax reduction of net income) in excess of the amount recorded as of December 31, 2015. It is also possible the outcome of these matters could differ from the estimated range of losses and materially affect our consolidated results of operations due to the uncertainty of the calculation of an authorized base ROE along with the zone of reasonableness under the newly adopted two-step DCF methodology, which is subject to significant discretion by the FERC. As of December 31, 2015, our MISO Regulated Operating Subsidiaries had a total of approximately $2.9 billion of equity in their collective capital structures for ratemaking purposes. Based on this level of aggregate equity, we estimate that each 10 basis point reduction in the authorized ROE would reduce annual consolidated net income by approximately $2.9 million.
In a separate but related matter, in November 2014, METC, ITC Midwest and other MISO TOs filed a request with FERC, under FPA Section 205, for authority to include a 50 basis point incentive adder for RTO participation in each of the TOs’ formula rates. On January 5, 2015, FERC approved the use of this incentive adder, effective January 6, 2015. Additionally, ITC Midwest filed a request with FERC, under FPA Section 205, in January 2015 for authority to include a 100 basis point incentive adder for independent transmission ownership, which is currently authorized for ITCTransmission and METC. On March 31, 2015, FERC approved the use of a 50 basis point incentive adder for independence, effective April 1, 2015. On April 30, 2015, ITC Midwest filed a request with FERC for rehearing on the approved incentive adder for independence. On January 6, 2016, the request for rehearing was denied by FERC. The RTO participation incentive adder will be applied to METC’s and ITC Midwest’s base ROEs and the independence incentive adder will be applied to ITC Midwest’s base ROE in establishing their total authorized ROE rates, subject to the limitations of the top end of any zone of reasonableness that is established. Collection of these recently approved incentive adders is being deferred pending the outcome of the ROE complaints.
Accelerated Share Repurchase Program
In April 2014, our board of directors authorized and ITC Holdings announced a share repurchase program for up to $250.0 million, which expired on December 31, 2015. Pursuant to such authorization, on June 19, 2014, ITC Holdings entered into an accelerated share repurchase agreement with JP Morgan Chase (“2014 ASR Program”) for up to $150.0 million, with a minimum commitment of $130.0 million, under which ITC Holdings was delivered 2.9 million shares with a fair market value of $104.0 million at the commencement of the 2014 ASR Program. On December 22, 2014, the 2014 ASR Program was settled for $130.0 million and ITC Holdings received an additional 0.7 million shares as determined by the volume-weighted average share price during the term of the 2014 ASR Program less an agreed upon discount and adjusted for the initial share delivery.
On September 30, 2015, ITC Holdings entered into another accelerated share repurchase agreement (the “2015 ASR Program”) with Barclays Bank PLC (“Barclays”) for $115.0 million pursuant to the board of directors’ authorization in April 2014. Under the 2015 ASR Program, ITC Holdings paid $115.0 million to Barclays on September 30, 2015 and received an initial delivery of 2.8 million shares on October 1, 2015. The fair market value of the initial delivery of shares was $92.0 million, based on the closing market price of $33.34 per share at the commencement of the 2015 ASR Program. The 2015 ASR Program was settled on November 5, 2015 and ITC Holdings received an additional 0.8 million shares as determined by the volume-weighted average share price during the term of the 2015 ASR Program, less an agreed upon discount and adjusted for the initial share delivery. See further discussion in Notes 9 and 13 to the consolidated financial statements.


36


MISO Formula Rate Template Modifications Filing
On October 30, 2015, ITCTransmission, METC and ITC Midwest (collectively, the “joint applicants”) requested modifications, pursuant to Section 205 of the FPA, to certain aspects of the joint applicants’ respective formula rate templates which included, among other things, changes to ensure that various income tax items are computed correctly for purposes of determining their revenue requirements. The joint applicants requested an effective date of January 1, 2016 for the proposed template changes. On December 30, 2015, the FERC conditionally accepted the formula rate template modifications and required a further compliance filing, which was made on February 8, 2016. The formula rate templates, prior to any proposed modifications, include certain deferred income taxes on contributions in aid of construction in rate base that resulted in the joint applicants recovering excess amounts from customers. The recognition of this refund liability in 2015 resulted in a reduction in revenues of $9.5 million, which includes amounts recovered for all historical periods through December 31, 2015, and an increase in interest expense of $0.9 million for the year ended December 31, 2015. This resulted in an estimated after-tax reduction to net income of $6.2 million for the year ended December 31, 2015. We do not expect the final resolution of this matter will differ materially from the amounts recorded in 2015.
Significant Components of Results of Operations
Revenues
We derive nearly all of our revenues from providing transmission, scheduling, control and dispatch services and other related services over our Regulated Operating Subsidiaries’ transmission systems to DTE Electric, Consumers Energy, IP&L and other entities, such as alternative electricity suppliers, power marketers and other wholesale customers that provide electricity to end-use consumers, as well as from transaction-based capacity reservations on our transmission systems. MISO and SPP are responsible for billing and collecting the majority of transmission service revenues. As the billing agent for our Regulated Operating Subsidiaries, MISO and SPP collect fees for the use of our transmission systems, invoicing DTE Electric, Consumers Energy, IP&L and other customers on a monthly basis.
Network Revenues are generated from network customers for their use of our electric transmission systems and are based on the actual revenue requirements as a result of our accounting under our cost-based formula rates that contain a true-up mechanism. Refer to “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates — Revenue Recognition under Cost-Based Formula Rates with True-Up Mechanisms” for a discussion of revenue recognition relating to network revenues.
Network revenues from ITC Great Plains include the annual revenue requirements specific to projects that are charged exclusively within one pricing zone within SPP or are classified as direct assigned network upgrades under the SPP tariff, and contain a true-up mechanism.
Point-to-Point Revenues consist of revenues generated from a type of transmission service for which the customer pays for transmission capacity reserved along a specified path between two points on an hourly, daily, weekly or monthly basis. Point-to-point revenues also include other components pursuant to schedules under the MISO and SPP transmission tariffs. Point-to-point revenues are treated as a revenue credit to network or regional customers and are a reduction to gross revenue requirement when calculating net revenue requirement under our cost-based formula rates.
Regional Cost Sharing Revenues are generated from transmission customers throughout RTO regions for their use of our MISO Regulated Operating Subsidiaries’ network upgrade projects that are eligible for regional cost sharing under provisions of the MISO tariff, including MVP projects such as the Thumb Loop Project. Regional cost sharing revenue also includes revenues collected by transmission customers from other RTOs outside of MISO to allocate costs of certain transmission plant investments. Additionally, certain projects at ITC Great Plains are eligible for recovery through a region-wide charge under provisions of the SPP tariff. A portion of regional cost sharing revenues is treated as a revenue credit to regional or network customers and is a reduction to gross revenue requirement when calculating net revenue requirement under our cost-based formula rates.
Scheduling, Control and Dispatch Revenues are allocated to our MISO Regulated Operating Subsidiaries by MISO as compensation for the services performed in operating the transmission system. Such services include monitoring of reliability data, current and next day analysis, implementation of emergency procedures and outage coordination and switching.


37


Other Revenues consist of rental revenues, easement revenues, revenues relating to utilization of jointly owned assets under our transmission ownership and operating agreements and amounts from providing ancillary services to customers. The majority of other revenues are treated as a revenue credit and taken as a reduction to gross revenue requirement when calculating net revenue requirement under our cost-based formula rates.
Operating Expenses
Operation and Maintenance Expenses consist primarily of the costs for contractors that operate and maintain our transmission systems as well as our personnel involved in operation and maintenance activities.
Operation expenses include activities related to control area operations, which involve balancing loads and generation and transmission system operations activities, including monitoring the status of our transmission lines and stations. Rental expenses relating to land easements, including METC’s Easement Agreement, are also recorded within operation expenses.
Maintenance expenses include preventive or planned maintenance, such as vegetation management, tower painting and equipment inspections, as well as reactive maintenance for equipment failures.
General and Administrative Expenses consist primarily of costs for personnel in our legal, information technology, finance, regulatory, human resources and business development organizations, general office expenses and fees for professional services. Professional services are principally composed of outside legal, consulting, audit and information technology services.
Depreciation and Amortization Expenses consist primarily of depreciation of property, plant and equipment using the straight-line method of accounting. Additionally, this consists of amortization of various regulatory and intangible assets.
Taxes Other than Income Taxes consist primarily of property taxes and payroll taxes.
Other Items of Income or Expense
Interest Expense consists primarily of interest on debt at ITC Holdings and our Regulated Operating Subsidiaries. Additionally, the amortization of debt financing expenses is recorded to interest expense. An allowance for borrowed funds used during construction is included in property, plant and equipment accounts and treated as a reduction to interest expense. The amortization of gains and losses on settled and terminated derivative financial instruments is also recorded to interest expense.
Allowance for Equity Funds Used During Construction (“AFUDC equity”) is recorded as an item of other income and is included in property, plant and equipment accounts. The allowance represents a return on equity at our Regulated Operating Subsidiaries used for construction purposes in accordance with 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.


38


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 thousands)
2015
 
2014
 
(Decrease)
 
(Decrease)
 
2013
 
(Decrease)
 
(Decrease)
OPERATING REVENUES
$
1,044,768

 
$
1,023,048

 
$
21,720

 
2.1%
 
$
941,272

 
$
81,776

 
8.7%
OPERATING EXPENSES
 
 
 
 
 
 
 
 
 
 
 
 
 
Operation and maintenance
113,123

 
111,623

 
1,500

 
1.3%
 
112,821

 
(1,198
)
 
(1.1)%
General and administrative
144,919

 
115,031

 
29,888

 
26.0%
 
149,109

 
(34,078
)
 
(22.9)%
Depreciation and amortization
144,672

 
128,036

 
16,636

 
13.0%
 
118,596

 
9,440

 
8.0%
Taxes other than income taxes
82,354

 
76,534

 
5,820

 
7.6%
 
65,824

 
10,710

 
16.3%
Other operating income and expenses — net
(1,017
)
 
(1,005
)
 
(12
)
 
1.2%
 
(1,139
)
 
134

 
(11.8)%
Total operating expenses
484,051

 
430,219

 
53,832

 
12.5%
 
445,211

 
(14,992
)
 
(3.4)%
OPERATING INCOME
560,717

 
592,829

 
(32,112
)
 
(5.4)%
 
496,061

 
96,768

 
19.5%
OTHER EXPENSES (INCOME)
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest expense — net
203,779

 
186,636

 
17,143

 
9.2%
 
168,319

 
18,317

 
10.9%
Allowance for equity funds used during construction
(28,075
)
 
(20,825
)
 
(7,250
)
 
34.8%
 
(30,159
)
 
9,334

 
(30.9)%
Loss on extinguishment of debt

 
29,205

 
(29,205
)
 
(100.0)%
 

 
29,205

 
n/a
Other income
(2,071
)
 
(1,103
)
 
(968
)
 
87.8%
 
(1,038
)
 
(65
)
 
6.3%
Other expense
3,207

 
4,511

 
(1,304
)
 
(28.9)%
 
6,571

 
(2,060
)
 
(31.3)%
Total other expenses (income)
176,840

 
198,424

 
(21,584
)
 
(10.9)%
 
143,693

 
54,731

 
38.1%
INCOME BEFORE INCOME TAXES
383,877

 
394,405

 
(10,528
)
 
(2.7)%
 
352,368

 
42,037

 
11.9%
INCOME TAX PROVISION
141,471

 
150,322

 
(8,851
)
 
(5.9)%
 
118,862

 
31,460

 
26.5%
NET INCOME
$
242,406

 
$
244,083

 
$
(1,677
)
 
(0.7)%
 
$
233,506

 
$
10,577

 
4.5%
Operating Revenues
Year ended December 31, 2015 compared to year ended December 31, 2014
The following table sets forth the components of and changes in operating revenues:
 
 
 
 
 
 
 
 
 
 
 
Percentage
 
2015
 
2014
 
Increase
 
Increase
(In thousands)
Amount
 
Percentage
 
Amount
 
Percentage
 
(Decrease)
 
(Decrease)
Network revenues
$
802,337

 
76.8
 %
 
$
763,954

 
74.7
 %
 
$
38,383

 
5.0
 %
Regional cost sharing revenues
327,349

 
31.3
 %
 
265,294

 
25.9
 %
 
62,055

 
23.4
 %
Point-to-point
15,381

 
1.5
 %
 
17,788

 
1.7
 %
 
(2,407
)
 
(13.5
)%
Scheduling, control and dispatch
13,163

 
1.3
 %
 
12,466

 
1.2
 %
 
697

 
5.6
 %
Other
11,298

 
1.1
 %
 
10,456

 
1.0
 %
 
842

 
8.1
 %
Recognition of refund liabilities
(124,760
)
 
(12.0
)%
 
(46,910
)
 
(4.5
)%
 
(77,850
)
 
166.0
 %
Total
$
1,044,768

 
100.0
 %
 
$
1,023,048

 
100.0
 %
 
$
21,720

 
2.1
 %
Network revenues increased due primarily to higher net revenue requirements at our Regulated Operating Subsidiaries, partially offset by higher regional revenue requirements, during the year ended December 31, 2015 as compared to 2014. Higher net revenue requirements were due primarily to higher rate bases associated with higher balances of property, plant and equipment in-service in 2015.
Regional cost sharing revenues increased primarily due to additional capital projects identified by MISO and SPP as eligible for regional cost sharing and these projects being placed in-service, in addition to higher accumulated investment for the Thumb Loop Project and Kansas V-Plan Project during the year ended December 31, 2015 as compared to the same period in 2014. We expect to continue to receive regional cost sharing revenues and the amounts could increase in the near future, including revenues associated with projects that have been or are expected to be approved for regional cost sharing.


39


The recognition of the refund liabilities for the refund relating to the formula rate template modifications and the potential refund relating to the ROE complaints described in Notes 4 and 16 to the consolidated financial statements, respectively, resulted in a reduction to operating revenues totaling $124.8 million and $46.9 million during the years ended December 31, 2015 and 2014, respectively. We are not able to estimate whether any required refunds would be applied to all components of revenue listed in the table above or only certain components.
Operating revenues for the years ended December 31, 2015 and 2014 include revenue accruals and deferrals as described in Note 4 to the consolidated financial statements.
Year ended December 31, 2014 compared to year ended December 31, 2013
The following table sets forth the components of and changes in operating revenues:
 
 
 
 
 
 
 
 
 
 
 
Percentage
 
2014
 
2013
 
Increase
 
Increase
(In thousands)
Amount
 
Percentage
 
Amount
 
Percentage
 
(Decrease)
 
(Decrease)
Network revenues
$
763,954

 
74.7
 %
 
$
726,161

 
77.1
%
 
$
37,793

 
5.2
%
Regional cost sharing revenues
265,294

 
25.9
 %
 
177,364

 
18.8
%
 
87,930

 
49.6
%
Point-to-point
17,788

 
1.7
 %
 
17,312

 
1.8
%
 
476

 
2.7
%
Scheduling, control and dispatch
12,466

 
1.2
 %
 
12,226

 
1.3
%
 
240

 
2.0
%
Other
10,456

 
1.0
 %
 
8,209

 
1.0
%
 
2,247

 
27.4
%
Recognition of refund liability
(46,910
)
 
(4.5
)%
 

 
%
 
(46,910
)
 
n/a

Total
$
1,023,048

 
100.0
 %
 
$
941,272

 
100.0
%
 
$
81,776

 
8.7
%
Network revenues increased due primarily to higher net revenue requirements at our Regulated Operating Subsidiaries during the year ended December 31, 2014 as compared to 2013. Higher net revenue requirements were due primarily to higher rate bases associated with higher balances of property, plant and equipment in-service in 2014.
Regional cost sharing revenues increased due primarily to additional capital projects that have been identified by MISO and SPP as eligible for regional cost sharing and these projects being placed in-service.
The recognition of the refund liability for the potential refund relating to the ROE complaints resulted in a reduction to operating revenues of $46.9 million during the fourth quarter of 2014 as described in Note 16 to the consolidated financial statements. We are not able to estimate whether any required refund would be applied to all components of revenues listed in the table above or only certain components.
Operating revenues for the years ended December 31, 2014 and 2013 include revenue accruals and deferrals as described in Note 4 to the consolidated financial statements.
Operating Expenses
Operation and maintenance expenses
Year ended December 31, 2015 compared to year ended December 31, 2014
Operation and maintenance expenses increased due primarily to higher operating expenses for transmission system monitoring and control activities at our MISO Regulated Operating Subsidiaries of $1.5 million.
Year ended December 31, 2014 compared to year ended December 31, 2013
Operation and maintenance expenses decreased due primarily to lower vegetation management requirements of $1.4 million.
General and administrative expenses
Year ended December 31, 2015 compared to year ended December 31, 2014
General and administrative expenses increased due primarily to higher compensation-related expenses of $17.4 million, mainly due to additional development bonuses described above under “Capital Project Updates and Other Recent Developments — Development Bonuses” of $7.8 million, and higher professional services such as legal and advisory services fees primarily for various development initiatives of $9.5 million.


40


Year ended December 31, 2014 compared to year ended December 31, 2013
General and administrative expenses decreased by $42.7 million due to legal, advisory and financial services fees incurred in the prior period relating to the terminated Entergy Transaction. The decrease was partially offset by higher professional services such as legal, advisory and financial services fees primarily for various development initiatives of $8.2 million unrelated to the Entergy Transaction.
Depreciation and amortization expenses
Year ended December 31, 2015 compared to year ended December 31, 2014
Depreciation and amortization expenses increased due primarily to a higher depreciable base resulting from property, plant and equipment in-service additions.
Year ended December 31, 2014 compared to year ended December 31, 2013
Depreciation and amortization expenses increased due primarily to a higher depreciable base resulting from property, plant and equipment in-service additions.
Taxes other than income taxes
Year ended December 31, 2015 compared to year ended December 31, 2014
Taxes other than income taxes increased due to higher property tax expenses primarily due to our Regulated Operating Subsidiaries’ 2014 capital additions, which are included in the assessments for 2015 property taxes.
Year ended December 31, 2014 compared to year ended December 31, 2013
Taxes other than income taxes increased due to higher property tax expenses primarily due to our Regulated Operating Subsidiaries’ 2013 capital additions, which are included in the assessments for 2014 property taxes.
Other expenses (income)
Year ended December 31, 2015 compared to year ended December 31, 2014
Interest expense increased due primarily to additional interest expense associated with the net issuance of $300.0 million in long-term debt securities subsequent to September 30, 2014 and the refund liabilities described in Notes 4 and 16 to the consolidated financial statements. These increases were partially offset by an increase in the allowance for borrowed funds used during construction (“AFUDC debt”), which is a reduction to interest expense, due primarily to higher balances of construction work in progress eligible for AFUDC debt during the period.
AFUDC equity increased due primarily to higher balances of construction work in progress eligible for AFUDC equity during the period.
Year ended December 31, 2014 compared to year ended December 31, 2013
Interest expense increased primarily due to interest associated with the long-term debt issuances at ITC Holdings and the Regulated Operating Subsidiaries which were used for refinancing of current debt maturities and general corporate purposes as described in Note 8 to the consolidated financial statements.
AFUDC equity decreased due primarily to lower balances of construction work in progress eligible for AFUDC equity during the period.
The loss on extinguishment of debt in 2014 related to the partial tender and retirement of $115.6 million of the 5.875% ITC Holdings Senior Notes and $54.7 million of the 6.375% ITC Holdings Senior Notes as described in Note 8 to the consolidated financial statements.
Income Tax Provision
Year ended December 31, 2015 compared to year ended December 31, 2014
Our effective tax rates for the years ended December 31, 2015 and 2014 are 36.9% and 38.1%, respectively. Our effective tax rate in both periods exceeded our 35% statutory federal income tax rate due primarily to state income taxes, partially offset by the tax effects of AFUDC equity. The amount of income tax expense relating to AFUDC equity was recognized as a regulatory asset and not included in the income tax provision.


41


Year ended December 31, 2014 compared to year ended December 31, 2013
Our effective tax rates for the years ended December 31, 2014 and 2013 are 38.1% and 33.7%, respectively. Our effective tax rate differs from our 35% statutory federal income tax rate due primarily to state income taxes as well as the tax effects of AFUDC equity. The amount of income tax expense relating to AFUDC equity was recognized as a regulatory asset and not included in the income tax provision. Additionally, during the fourth quarter of 2013, due to the cancellation of the Entergy Transaction, we recognized tax benefits for expenses that were previously deemed non-deductible for tax purposes, including a decrease to the tax provision of $5.6 million for expenses that were incurred in 2012 and 2011.
Liquidity and Capital Resources
We expect to maintain our approach to fund our future capital requirements with cash from operations at our Regulated Operating Subsidiaries, our existing cash and cash equivalents, issuances under our commercial paper program and amounts available under our revolving credit agreements (the terms of which are described in Note 8 to the consolidated financial statements). In addition, we may from time to time secure debt and equity funding in the capital markets, although we can provide no assurance that we will be able to obtain financing on favorable terms or at all. As market conditions warrant, we may also from time to time repurchase debt or equity securities issued by us, in the open market, in privately negotiated transactions, by tender offer or otherwise. We expect that our capital requirements will arise principally from our need to:
Fund capital expenditures at our Regulated Operating Subsidiaries. Our plans with regard to property, plant and equipment investments are described in detail above under “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Investment and Operating Results Trends.”
Fund business development expenses and related capital expenditures. We are pursuing development activities for transmission projects that will continue to result in the incurrence of development expenses and could result in significant capital expenditures.
Fund working capital requirements.
Fund our debt service requirements including principal repayments and periodic interest payments, which are further described in detail below under “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Contractual Obligations.” We expect our interest payments to increase each year as a result of additional debt expected to be incurred to fund our capital expenditures and for general corporate purposes.
Fund contributions to our retirement benefit plans, as described in Note 11 to the consolidated financial statements. We expect to contribute up to $12.0 million to these plans in 2016.
In addition to the expected capital requirements above, any adverse determinations relating to the regulatory matters or contingencies described in Notes 4 and 16 to the consolidated financial statements would result in additional capital requirements.
We believe that we have sufficient capital resources to meet our currently anticipated short-term needs. We rely on both internal and external sources of liquidity to provide working capital and fund capital investments. ITC Holdings’ sources of cash are dividends and other payments received by us from our Regulated Operating Subsidiaries and any of our other subsidiaries as well as the proceeds raised from the sale of our debt and equity securities. Each of our Regulated Operating Subsidiaries, while wholly owned by ITC Holdings, is legally distinct from ITC Holdings and has no obligation, contingent or otherwise, to make funds available to us.
We expect to continue to utilize our commercial paper program and revolving credit agreements as well as our cash and cash equivalents as needed to meet our short-term cash requirements. As of December 31, 2015, we had consolidated indebtedness under our revolving and term loan credit agreements of $680.9 million, with unused capacity under the revolving credit agreements of $680.1 million. Additionally, ITC Holdings had $95.0 million of commercial paper issued and outstanding as of December 31, 2015 with the ability to issue an additional $305.0 million under the commercial paper program. See Note 8 to the consolidated financial statements for a detailed discussion of the commercial paper program and our revolving credit agreements as well as the debt activity during the years ended December 31, 2015 and 2014.


42


As of December 31, 2015, we had approximately $395.3 million of debt maturing within one year, which we expect to refinance with long-term debt. To address our long-term capital requirements as well as repay debt maturing within one year, we expect that we will need to obtain additional debt financing. Certain of our capital projects could be delayed if we experience difficulties in accessing capital. We expect to be able to obtain such additional financing as needed, in amounts and upon terms that will be reasonably satisfactory to us due to our strong credit ratings and our historical ability to obtain financing.
Credit Ratings
Credit ratings by nationally recognized statistical rating agencies are an important component of our liquidity profile. Credit ratings relate to our ability to issue debt securities and the cost to borrow money, and should not be viewed as an indication of future stock performance or a recommendation to buy, sell or hold securities. Ratings are subject to revision or withdrawal at any time and each rating should be evaluated independently of any other rating. Our current credit ratings are displayed in the following table. An explanation of these ratings may be obtained from the respective rating agency.
 
 
 
 
Standard and Poor’s
 
Moody’s Investor
Issuer
 
Issuance
 
Ratings Services (a)
 
Service, Inc. (b)
ITC Holdings
 
Senior Unsecured Notes
 
BBB+
 
Baa2
ITC Holdings
 
Commercial Paper
 
A-2
 
Prime-2
ITCTransmission
 
First Mortgage Bonds
 
A
 
A1
METC
 
Senior Secured Notes
 
A
 
A1
ITC Midwest
 
First Mortgage Bonds
 
A
 
A1
ITC Great Plains
 
First Mortgage Bonds
 
A
 
A1
____________________________
(a)
On June 8, 2015, Standard and Poor’s Ratings Services (“Standard and Poor’s”) assigned a short-term issuer credit rating to ITC Holdings, which applies to the commercial paper program discussed in Note 8 to the consolidated financial statements. Additionally, on December 3, 2015, Standard and Poor’s reaffirmed the senior unsecured credit rating of ITC Holdings and the secured credit ratings of the Regulated Operating Subsidiaries. On February 9, 2016, Standard and Poor’s revised the outlook of the issuer credit ratings of ITC Holdings and the Regulated Operating Subsidiaries to negative from developing, subsequent to the announcement of the Merger.
(b)
On April 15, 2015, Moody’s Investor Service, Inc. (“Moody’s) reaffirmed the credit ratings for ITC Holdings and the Regulated Operating Subsidiaries. Additionally, on June 9, 2015, Moody’s assigned a short-term commercial paper rating to ITC Holdings, which applies to the commercial paper program discussed in Note 8 to the consolidated financial statements. All of the credit ratings have a stable outlook.
Covenants
Our debt instruments contain numerous financial and operating covenants that place significant restrictions on certain transactions as well as require us to meet certain financial ratios, which are described in Note 8 to the consolidated financial statements. As of December 31, 2015, we were not in violation of any debt covenant. In the event of a downgrade in our credit ratings, none of the covenants would be directly impacted, although the borrowing costs under our revolving and term loan credit agreements would increase.


43


Cash Flows
The following table summarizes cash flows for the periods indicated:
 
Year Ended December 31,
(In thousands)
2015
 
2014
 
2013
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
 
 
Net income
$
242,406

 
$
244,083

 
$
233,506

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
 
Depreciation and amortization expense
144,672

 
128,036

 
118,596

Recognition of and refund and collection of revenue accruals and deferrals — including accrued interest
(53,539
)
 
(4,093
)
 
(11,972
)
Deferred income tax expense
77,371

 
90,373

 
76,703

Tax benefit for excess tax deductions of share-based compensation
(11,707
)
 
(7,767
)
 
(4,302
)
Other
156,542

 
50,869

 
36,665

Net cash provided by operating activities
555,745

 
501,501

 
449,196

CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
 
 
Expenditures for property, plant and equipment
(684,140
)
 
(733,145
)
 
(821,588
)
Other
(15,205
)
 
(1,556
)
 
(4,700
)
Net cash used in investing activities
(699,345
)
 
(734,701
)
 
(826,288
)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
 
 
Net issuance/repayment of debt (including commercial paper and revolving and term loan credit agreements)
351,730

 
462,639

 
464,425

Issuance of common stock
13,635

 
20,713

 
10,042

Dividends on common and restricted stock
(108,275
)
 
(95,595
)
 
(84,129
)
Refundable deposits from and repayments to generators for transmission network upgrades — net
931

 
(22,850
)
 
(5,955
)
Repurchase and retirement of common stock
(137,081
)
 
(134,284
)
 
(4,885
)
Tax benefit for excess tax deductions of share-based compensation
11,707

 
7,767

 
4,302

Other
(2,929
)
 
(11,724
)
 
1,380

Net cash provided by financing activities
129,718

 
226,666

 
385,180

NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS
(13,882
)
 
(6,534
)
 
8,088

CASH AND CASH EQUIVALENTS — Beginning of period
27,741

 
34,275

 
26,187

CASH AND CASH EQUIVALENTS — End of period
$
13,859

 
$
27,741

 
$
34,275

Cash Flows From Operating Activities
Year ended December 31, 2015 compared to year ended December 31, 2014
Net cash provided by operating activities increased $54.2 million in 2015 compared to 2014. The increase in cash provided by operating activities was due primarily to an increase in cash received from operating revenues of $70.3 million during 2015 compared to 2014. This increase was partially offset by an increase in payments of operating expenses of $25.4 million.
Year ended December 31, 2014 compared to year ended December 31, 2013
Net cash provided by operating activities increased $52.3 million in 2014 compared to 2013. The increase in cash provided by operating activities was due primarily to an increase in cash received from operating revenues of $132.7 million during 2014 compared to 2013. This increase was partially offset by higher interest payments (net of interest capitalized) of $30.2 million, higher income taxes paid of $24.4 million and an increase in payments of operating expenses of $12.1 million.


44


Cash Flows From Investing Activities
Year ended December 31, 2015 compared to year ended December 31, 2014
Net cash used in investing activities decreased $35.4 million in 2015 compared to 2014. The decrease in cash used in investing activities was due primarily to the timing of payments for investments in property, plant and equipment during the year ended December 31, 2015 compared to the same period in 2014.
Year ended December 31, 2014 compared to year ended December 31, 2013
Net cash used in investing activities decreased $91.6 million in 2014 compared to 2013. The decrease in cash used in investing activities was due primarily to lower investments in property, plant and equipment during 2014 as we executed our capital investment plan described above under “— Overview — Capital Investment and Operating Results Trends.”
Cash Flows From Financing Activities
Year ended December 31, 2015 compared to year ended December 31, 2014
Net cash provided by financing activities decreased $96.9 million in 2015 compared to 2014. The decrease in cash provided by financing activities was due primarily to a decrease in long-term debt issuances of $573.7 million during 2015 compared to 2014. This decrease was partially offset by a net increase of $244.5 million in amounts outstanding under our revolving and term loan credit agreements, a decrease in payments of $123.6 million to retire long-term debt, the $94.6 million in net proceeds from the issuance of commercial paper under our commercial paper program during the year ended December 31, 2015 and lower net payments of $23.8 million associated with refundable deposits for transmission network upgrades. See Note 8 to the consolidated financial statements for detail on the issuances and retirements of debt.
Year ended December 31, 2014 compared to year ended December 31, 2013
Net cash provided by financing activities decreased $158.5 million in 2014 compared to 2013. The decrease in cash provided by financing activities was due primarily to a decrease in long-term debt issuances of $134.4 million during 2014 compared to 2013 as well as the net payment of $130.0 million for the 2014 ASR Program as described in Note 13 to the consolidated financial statements. Additionally, there was a net decrease of $20.8 million in amounts outstanding under our revolving and term loan credit agreements and lower net proceeds of $16.9 million associated with refundable deposits for transmission network upgrades. These decreases were partially offset by a decrease in payments of $153.4 million to retire long-term debt. See Note 8 to the consolidated financial statements for detail on the issuances and retirements of long-term debt.


45


Contractual Obligations
The following table details our contractual obligations as of December 31, 2015:
 
 
 
Less Than
 
1-3
 
4-5
 
More Than
(In thousands)
Total
 
1 Year
 
Years
 
Years
 
5 Years
Debt:
 
 
 
 
 
 
 
 
 
ITC Holdings Senior Notes
$
1,924,684

 
$
139,344

 
$
435,000

 
$
200,000

 
$
1,150,340

ITC Holdings revolving credit agreement
137,700

 

 
137,700

 

 

ITC Holdings commercial paper program
95,000

 
95,000

 

 

 

ITC Holdings term loan credit agreement
161,000

 
161,000

 

 

 

ITCTransmission First Mortgage Bonds
585,000

 

 
100,000

 

 
485,000

ITCTransmission revolving credit agreement
48,300

 

 
48,300

 

 

METC Senior Secured Notes
275,000

 

 

 

 
275,000

METC revolving credit agreement
2,500

 

 
2,500

 

 

METC term loan credit agreement
200,000

 

 
200,000

 

 

ITC Midwest First Mortgage Bonds
750,000

 

 
40,000

 
35,000

 
675,000

ITC Midwest revolving credit agreement
72,300

 

 
72,300

 

 

ITC Great Plains First Mortgage Bonds
150,000

 

 

 

 
150,000

ITC Great Plains revolving credit agreement
59,100

 

 
59,100

 

 

Interest payments:
 
 
 
 
 
 
 
 
 
ITC Holdings Senior Notes
1,006,043

 
96,922

 
220,665

 
107,221

 
581,235

ITCTransmission First Mortgage Bonds
601,161

 
29,326

 
65,107

 
38,613

 
468,115

METC Senior Secured Notes
345,264

 
12,090

 
36,270

 
24,180

 
272,724

ITC Midwest First Mortgage Bonds
771,184

 
31,286

 
101,672

 
63,321

 
574,905

ITC Great Plains First Mortgage Bonds
180,353

 
6,240

 
18,720

 
12,480

 
142,913

Operating leases
4,972

 
932

 
2,069

 
955

 
1,016

Purchase obligations
61,368

 
60,088

 
1,280

 

 

Regulatory liabilities — revenue deferrals, including accrued interest
42,970

 
36,639

 
6,331

 

 

Regulatory liabilities — refund related to the formula rate template modifications, including accrued interest
10,424

 
8,154

 
2,270

 

 

METC Easement Agreement
349,680

 
10,041

 
30,123

 
20,082

 
289,434

Total obligations
$
7,834,003

 
$
687,062

 
$
1,579,407

 
$
501,852

 
$
5,065,682

Interest payments included above relate only to our fixed-rate long-term debt outstanding at December 31, 2015. We also expect to pay interest and commitment fees under our variable-rate revolving and term loan credit agreements that have not been included above due to varying amounts of borrowings and interest rates under the facilities. In 2015, we paid $6.4 million of interest and commitment fees under our revolving and term loan credit agreements.
Operating leases include leases for office space, equipment and storage facilities. Purchase obligations represent commitments primarily for materials, services and equipment that had not been received as of December 31, 2015, primarily for construction and maintenance projects for which we have an executed contract. The majority of the items relate to materials and equipment that have long production lead times. See Note 16 to the consolidated financial statement for more information on our operating leases and purchases obligations.
The regulatory liabilities — revenue deferrals, including accrued interest, in the table above represents the over-recovery of revenues resulting from differences between the amounts billed to customers and actual revenue requirement at each of our Regulated Operating Subsidiaries, as described in Note 4 to the consolidated financial statements. These amounts will offset future revenue requirement for purposes of calculating our formula rates as part of the true-up mechanism in our rate construct.


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The Easement Agreement provides METC with an easement for transmission purposes and rights-of-way, leasehold interests, fee interests and licenses associated with the land over which the transmission lines cross. The cost for use of the rights-of-way is $10.0 million per year. The term of the Easement Agreement runs through December 31, 2050 and is subject to 10 automatic 50-year renewals thereafter unless METC gives notice of nonrenewal of at least one year in advance. Payments to Consumers Energy under the Easement Agreement are charged to operation and maintenance expense.
The contractual obligations table above excludes certain items, including contingent liabilities and other long-term liabilities, due to uncertainty on the final outcome in addition to the timing and amount of future cash flows necessary to settle these obligations. The amount of cash flows to be paid for pension and other postretirement obligations and settle regulatory liabilities related to asset removal costs and liabilities to refund deposits from generators for transmission network upgrades, which are recorded in other current and long term liabilities, are not known with certainty. As a result, cash obligations for these items are excluded from the contractual obligations table above.
Critical Accounting Policies and Estimates
Our consolidated financial statements are prepared in accordance with GAAP. The preparation of these consolidated financial statements requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. The application of these policies requires judgments regarding future events.
These estimates and judgments, in and of themselves, could materially impact the consolidated financial statements and disclosures based on varying assumptions, as future events rarely develop exactly as forecasted, and even the best estimates routinely require adjustment.
The following is a list of accounting policies that are most significant to the portrayal of our financial condition and results of operations and/or that require management’s most difficult, subjective or complex judgments.
Regulation
Nearly all of our Regulated Operating Subsidiaries’ business is subject to regulation by the FERC. As a result, we apply accounting principles in accordance with the standards set forth by the Financial Accounting Standards Board (“FASB”) for accounting for the effects of certain types of regulation. Use of this accounting guidance results in differences in the application of GAAP between regulated and non-regulated businesses and requires the recording of regulatory assets and liabilities for certain transactions that would have been treated as expense or revenue in non-regulated businesses. As described in Note 5 to the consolidated financial statements, we had regulatory assets and liabilities of $248.1 million and $299.8 million, respectively, as of December 31, 2015. Future changes in the regulatory and competitive environments could result in discontinuing the application of the accounting standards for the effects of certain types of regulations. If we were to discontinue the application of this guidance on our Regulated Operating Subsidiaries’ operations, we may be required to record losses relating to certain regulatory assets or gains relating to certain regulatory liabilities. We also may be required to record losses of $45.6 million relating to intangible assets at December 31, 2015 that are described in Note 6 to the consolidated financial statements.
We believe that currently available facts support the continued applicability of the standards for accounting for the effects of certain types of regulation and that all regulatory assets and liabilities are recoverable or refundable under our current rate environment.
Revenue Recognition under Cost-Based Formula Rates with True-Up Mechanism
Our Regulated Operating Subsidiaries recover expenses and earn a return on and recover investments in property, plant and equipment on a current, rather than lagging, basis, under their forward-looking cost-based formula rates with a true-up mechanism.
Under their formula rates, our Regulated Operating Subsidiaries use forecasted expenses, property, plant and equipment, point-to-point revenues and other items for the upcoming calendar year to establish their projected revenue requirement and for the MISO Regulated Operating Subsidiaries, their component of the billed network rates for service on their systems from January 1 to December 31 of that year. The cost-based formula rate templates include a true-up mechanism, whereby our Regulated Operating Subsidiaries compare their actual revenue requirements to their billed revenues for each year in order to subsequently collect or refund any under-recovery or over-recovery of revenues, as appropriate. The under- or over-collection typically results from


47


differences between the projected revenue requirement used as the basis for billing and actual revenue requirement at each of our Regulated Operating Subsidiaries, and from differences between actual and projected monthly peak loads at our MISO Regulated Operating Subsidiaries.
The true-up mechanism under our formula rates meet the GAAP requirements for accounting for rate-regulated utilities and the effects of certain alternative revenue programs. Accordingly, revenue is recognized during each reporting period based on actual revenue requirements calculated using the cost-based formula rate. Our Regulated Operating Subsidiaries accrue or defer revenues to the extent that their actual revenue requirement for the reporting period is higher or lower, respectively, than the amounts billed relating to that reporting period. The true-up amount is automatically reflected in customer bills within two years under the provisions of the formula rates. See Note 4 to the consolidated financial statements for the regulatory assets and liabilities recorded at our Regulated Operating Subsidiaries’ as a result of the formula rate revenue accruals and deferrals.
Valuation of Goodwill
We have goodwill resulting from our acquisitions of ITCTransmission and METC and ITC Midwest’s acquisition of the IP&L transmission assets. We perform an impairment test annually at the reporting unit level or whenever events or circumstances indicate that the value of goodwill may be impaired. In order to perform these impairment tests, we compare the fair value of each reporting unit with their respective carrying value. Our reporting units are ITCTransmission, METC and ITC Midwest as each of them represents an individual operating segment. We determine fair value using valuation techniques based on discounted future cash flows under various scenarios. We also consider estimates of market-based valuation multiples for companies within the peer group of our reporting units. The market-based multiples involve judgment regarding the appropriate peer group and the appropriate multiple to apply in the valuation and the cash flow estimates involve judgments based on a broad range of assumptions, information and historical results. To the extent estimated market-based valuation multiples and/or discounted cash flows are revised downward, we may be required to write down all or a portion of goodwill, which would adversely impact earnings.
As of December 31, 2015 and 2014, consolidated goodwill totaled $950.2 million. We completed our annual goodwill impairment test for our reporting units as of October 1, 2015 and determined that no impairment exists. There were no events subsequent to October 1, 2015 that indicated impairment of our goodwill. We do not believe there is a material risk of our goodwill being impaired in the near term for any of our reporting units given that their fair values are substantially in excess of their carrying values.
Contingent Obligations
We are subject to a number of federal and state laws and regulations, as well as other factors and conditions that potentially subject us to environmental, litigation, income tax and other contingencies. Additionally, we have other contingent obligations that may be required to be paid to developers based on achieving certain milestones relating to development initiatives. We periodically evaluate our exposure to such contingencies and record liabilities for those matters where a loss is considered probable and reasonably estimable in accordance with GAAP. Our liabilities exclude any estimates for legal costs not yet incurred associated with handling these matters, which could be material. The adequacy of liabilities recorded can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect our consolidated financial statements. These events or conditions include, without limitation, the following:
Changes in existing state or federal regulation by governmental authorities having jurisdiction over air quality, water quality, control of toxic substances, hazardous and solid wastes and other environmental matters.
Changes in existing federal income tax laws or Internal Revenue Service (“IRS”) regulations.
Identification and evaluation of lawsuits or complaints in which we may be or have been named as a defendant.
Resolution or progression of existing matters through the legislative process, the courts, the FERC, the NERC, the IRS or the Environmental Protection Agency.
Completion of certain milestones relating to development initiatives.
Refer to Note 16 to the consolidated financial statements for discussion on contingencies, including the ROE complaints.


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Pension and Postretirement Costs
We sponsor certain retirement benefits for our employees, which include retirement pension plans and certain postretirement health care, dental and life insurance benefits. Our periodic costs and obligations associated with these plans are developed from actuarial valuations derived from a number of assumptions, including rates of return on plan assets, the discount rates, the rate of increase in health care costs, the amount and timing of plan sponsor contributions and demographic factors such as retirements, mortality and turnover, among others. We evaluate these assumptions annually and update them periodically to reflect our actual experience. Three critical assumptions in determining our periodic costs and obligations are discount rate, expected long-term return on plan assets and the rate of increases in health care costs. The discount rate represents the market rate for synthesized AA-rated zero-coupon bonds with durations corresponding to the expected durations of the benefit obligations and is used to calculate the present value of the expected future cash flows for benefit obligations under our plans. In determining our long-term rate of return on plan assets, we consider the current and expected asset allocations, as well as historical and expected long-term rates of return on those types of asset classes. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans as described in Note 11 to the consolidated financial statements.
Off-Balance Sheet Arrangements
We have no off-balance sheet arrangements that have or are reasonably likely to have a material effect on our financial condition.
Recent Accounting Pronouncements
See Note 3 to the consolidated financial statements.
ITEM 7A.     QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Commodity Price Risk
We have commodity price risk at our Regulated Operating Subsidiaries arising from market price fluctuations for materials such as copper, aluminum, steel, oil and gas and other goods used in construction and maintenance activities. Higher costs of these materials are passed on to us by the contractors for these activities. These items affect only cash flows, as the amounts are included as components of net revenue requirement and any higher costs are included in rates under their cost-based formula rates.
Interest Rate Risk
Fixed Rate Debt
Based on the borrowing rates currently available for bank loans with similar terms and average maturities, the fair value of our consolidated long-term debt and debt maturing within one year, excluding revolving and term loan credit agreements and commercial paper, was $3,879.7 million at December 31, 2015. The total book value of our consolidated long-term debt and debt maturing within one year, net of discount and excluding revolving and term loan credit agreements and commercial paper, was $3,680.4 million at December 31, 2015. We performed an analysis calculating the impact of changes in interest rates on the fair value of long-term debt and debt maturing within one year, excluding our revolving and term loan credit agreements and commercial paper, at December 31, 2015. An increase in interest rates of 10% (from 7.0% to 7.7%, for example) at December 31, 2015 would decrease the fair value of debt by $159.3 million, and a decrease in interest rates of 10% at December 31, 2015 would increase the fair value of debt by $173.8 million at that date.
Revolving and Term Loan Credit Agreements
At December 31, 2015, we had a consolidated total of $680.9 million outstanding under our revolving and term loan credit agreements, which are variable rate loans and fair value approximates book value. A 10% increase or decrease in borrowing rates under the revolving and term loan credit agreements compared to the weighted average rates in effect at December 31, 2015 would increase or decrease the total interest expense by $1.0 million, respectively, for an annual period on a constant borrowing level of $680.9 million.
Commercial Paper
At December 31, 2015, ITC Holdings had $95.0 million of commercial paper issued and outstanding, net of discount, under the commercial paper program. Due to the short-term nature of these financial instruments, the


49


carrying value approximates fair value. A 10% increase or decrease in interest rates for commercial paper would increase or decrease interest expense by less than $0.1 million for an annual period with a continuous level of commercial paper outstanding of $95.0 million.
Derivative Instruments and Hedging Activities
We may use derivative financial instruments, including interest rate swap contracts, to manage our exposure to fluctuations in interest rates. The use of these financial instruments mitigates exposure to these risks and the variability of our operating results. We are not a party to leveraged derivatives and do not enter into derivative financial instruments for trading or speculative purposes. As of December 31, 2015, we held 10-year interest rate swaps with a notional amount of $75.0 million, which manage interest rate risk associated with the forecasted future issuance of fixed-rate debt related to the expected refinancing of the maturing ITC Holdings 5.875% Senior Notes, due September 30, 2016. As of December 31, 2015, ITC Holdings had $139.3 million outstanding under the 5.875% Senior Notes. ITC Holdings entered into two additional 10-year interest rate swaps in February 2016 with notional amounts of $25.0 million each, which also manage interest rate risk related to the expected refinancing of the 5.875% Senior Notes. See Note 8 to the consolidated financial statements for further discussion on these interest rate swaps.
Credit Risk
Our credit risk is primarily with DTE Electric, Consumers Energy and IP&L, which were responsible for 20.8%, 21.9% and 26.8%, respectively, or $232.6 million, $244.6 million and $299.9 million, respectively, of our consolidated billed revenues for 2015. These percentages of total billed revenues of DTE Electric, Consumers Energy and IP&L include the collection of 2013 revenue accruals and deferrals and exclude any amounts for the 2015 revenue accruals and deferrals that were included in our 2015 operating revenues, but will not be billed to our customers until 2017. Refer to Item 7 Managements Discussion and Analysis of Financial Condition and Results of Operations — Cost-Based Formula Rates with True-Up Mechanism for a discussion on the difference between billed revenues and operating revenues. Under DTE Electric’s and Consumers Energy’s current rate structure, DTE Electric and Consumers Energy include in their retail rates the actual cost of transmission services provided by ITCTransmission and METC, respectively, in their billings to their customers, effectively passing through to end-use consumers the total cost of transmission service. IP&L currently includes in their retail rates an allowance for transmission services provided by ITC Midwest in their billings to their customers. However, any financial difficulties experienced by DTE Electric, Consumers Energy or IP&L may affect their ability to make payments for transmission service to ITCTransmission, METC and ITC Midwest, which could negatively impact our business. MISO, as our MISO Regulated Operating Subsidiaries’ billing agent, bills DTE Electric, Consumers Energy, IP&L and other customers on a monthly basis and collects fees for the use of the MISO Regulated Operating Subsidiaries’ transmission systems. SPP is the billing agent for ITC Great Plains and bills transmission customers for the use of ITC Great Plains transmission systems. MISO and SPP have implemented strict credit policies for its members’ customers, which include customers using our transmission systems. Specifically, MISO and SPP require a letter of credit or cash deposit equal to the credit exposure, which is determined by a credit scoring model and other factors, from any customer using a member’s transmission system.


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ITEM 8.     FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
The following financial statements and schedules are included herein:
 
 
Page
Management’s Report on Internal Control over Financial Reporting
 
Report of Independent Registered Public Accounting Firm
 
Report of Independent Registered Public Accounting Firm
 
Consolidated Statements of Financial Position as of December 31, 2015 and 2014
 
Consolidated Statements of Operations for the Years Ended December 31, 2015, 2014 and 2013
 
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2015, 2014 and 2013
 
Consolidated Statements of Changes in Stockholders’ Equity for the Years Ended December 31, 2015, 2014 and 2013
 
Consolidated Statements of Cash Flows for the Years Ended December 31, 2015, 2014 and 2013
 
Notes to Consolidated Financial Statements
 
Schedule I — Condensed Financial Information of Registrant
 



51


MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is designed to provide reasonable, not absolute, assurance as to the reliability of our financial reporting and the preparation of financial statements in accordance with generally accepted accounting principles. Internal control over financial reporting, no matter how well designed, has inherent limitations. Therefore, internal control over financial reporting determined to be effective can provide only reasonable assurance with respect to financial statement preparation and may not prevent or detect all misstatements.
Under management’s supervision, an evaluation of the design and effectiveness of our internal control over financial reporting was conducted based on the criteria set forth in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Our assessment included extensive documenting, evaluating and testing of the design and operating effectiveness of our internal control over financial reporting. Based on this evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2015.
Deloitte & Touche LLP, an independent registered public accounting firm, as auditors of our consolidated financial statements, has issued an attestation report on the effectiveness of our internal control over financial reporting as of December 31, 2015. Deloitte & Touche LLP’s report, which expresses an unqualified opinion on the effectiveness of our internal control over financial reporting, is included herein.


52


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
ITC Holdings Corp.:
Novi, Michigan
We have audited the accompanying consolidated statements of financial position of ITC Holdings Corp. and subsidiaries (the “Company”) as of December 31, 2015 and 2014, and the related consolidated statements of operations, comprehensive income, changes in stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2015. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of ITC Holdings Corp. and subsidiaries as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2015, based on criteria established in the Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 25, 2016 expressed an unqualified opinion on the Company’s internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP

Detroit, Michigan
February 25, 2016


53


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
ITC Holdings Corp.:
Novi, Michigan
We have audited the internal control over financial reporting of ITC Holdings Corp. and subsidiaries (the “Company”) as of December 31, 2015, based on criteria established in the Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on the criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2015 of the Company and our report dated February 25, 2016 expressed an unqualified opinion on those financial statements and financial statement schedule.
/s/ DELOITTE & TOUCHE LLP

Detroit, Michigan
February 25, 2016


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ITC HOLDINGS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
 
December 31,
(In thousands, except share data)
2015
 
2014
ASSETS
Current assets
 
 
 
Cash and cash equivalents
$
13,859

 
$
27,741

Accounts receivable
104,262

 
100,998

Inventory
25,777

 
30,892

Regulatory assets
14,736

 
5,393

Prepaid and other current assets
10,608

 
7,281

Total current assets
169,242

 
172,305

Property, plant and equipment (net of accumulated depreciation and amortization of $1,487,713 and $1,388,217, respectively)
6,109,639

 
5,496,875