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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)



þ	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended December 31, 2015



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):

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.

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ITC Holdings Corp.

Form 10-K for the Fiscal Year Ended December 31, 2015

INDEX



		Page
PART I		5
Item 1.	Business	5
Item 1A.	Risk Factors	15
Item 1B.	Unresolved Staff Comments	24
Item 2.	Properties	24
Item 3.	Legal Proceedings	26
Item 4.	Mine Safety Disclosures	26

PART II		27
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	27
Item 6.	Selected Financial Data	29
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	30
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	49
Item 8.	Financial Statements and Supplementary Data	51
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	102
Item 9A.	Controls and Procedures	102
Item 9B.	Other Information	102

PART III		103
Item 10.	Directors, Executive Officers and Corporate Governance	103
Item 11.	Executive Compensation	103
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	103
Item 13.	Certain Relationships and Related Transactions, and Director Independence	103
Item 14.	Principal Accountant Fees and Services	103

PART IV		104
Item 15.	Exhibits and Financial Statement Schedules	104
Signatures		111
Exhibits		112

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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 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cost-Based Formula Rates with True-Up Mechanism” for a discussion on the difference between billed revenues and operating revenues. Our remaining revenues were generated from providing service to other entities such as alternative electricity suppliers, power marketers and other wholesale customers that provide electricity to end-use consumers and from transaction-based capacity reservations. Nearly all of our revenues are from transmission customers in the United States. Although we may recognize allocated revenues from time to time from Canadian entities reserving transmission over the Ontario or Manitoba interface, these revenues have not been and are not expected to be material to us.

Billing

MISO and SPP are responsible for billing and collecting the majority of our transmission service revenues as well as independently 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.

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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:

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•	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

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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.

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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

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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.

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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.

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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.

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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)
Period	Total Number of Shares Purchased (1)	Average Price Paid per Share
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

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____________________________


(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

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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.

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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,

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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

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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.

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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.

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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.

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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.

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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.

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Results of Operations

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



	Year Ended									Percentage	Year Ended						Percentage
	December 31,						Increase			Increase	December 31,			Increase			Increase
(In 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.

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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.

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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.

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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.

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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.

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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.

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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.

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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

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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

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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 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cost-Based Formula Rates with True-Up Mechanism” for a discussion on the difference between billed revenues and operating revenues. Under DTE Electric’s and Consumers Energy’s current rate structure, DTE Electric and Consumers Energy include in their retail rates the actual cost of transmission services provided by ITCTransmission and METC, respectively, in their billings to their customers, effectively passing through to end-use consumers the total cost of transmission service. IP&L currently includes in their retail rates an allowance for transmission services provided by ITC Midwest in their billings to their customers. However, any financial difficulties experienced by DTE Electric, Consumers Energy or IP&L may affect their ability to make payments for transmission service to ITCTransmission, METC and ITC Midwest, which could negatively impact our business. MISO, as our MISO Regulated Operating Subsidiaries’ billing agent, bills DTE Electric, Consumers Energy, IP&L and other customers on a monthly basis and collects fees for the use of the MISO Regulated Operating Subsidiaries’ transmission systems. SPP is the billing agent for ITC Great Plains and bills transmission customers for the use of ITC Great Plains transmission systems. MISO and SPP have implemented strict credit policies for its members’ customers, which include customers using our transmission systems. Specifically, MISO and SPP require a letter of credit or cash deposit equal to the credit exposure, which is determined by a credit scoring model and other factors, from any customer using a member’s transmission system.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

The following financial statements and schedules are included herein:



		Page
Management’s Report on Internal Control over Financial Reporting		52
Report of Independent Registered Public Accounting Firm		53
Report of Independent Registered Public Accounting Firm		54
Consolidated Statements of Financial Position as of December 31, 2015 and 2014		55
Consolidated Statements of Operations for the Years Ended December 31, 2015, 2014 and 2013		56
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2015, 2014 and 2013		57
Consolidated Statements of Changes in Stockholders’ Equity for the Years Ended December 31, 2015, 2014 and 2013		58
Consolidated Statements of Cash Flows for the Years Ended December 31, 2015, 2014 and 2013		59
Notes to Consolidated Financial Statements		60
Schedule I — Condensed Financial Information of Registrant		105

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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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

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

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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

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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
Other assets
Goodwill	950,163		950,163
Intangible assets (net of accumulated amortization of $28,242 and $24,917, respectively)	45,602		48,794
Regulatory assets	233,376		223,712
Deferred financing fees (net of accumulated amortization of $17,515 and $15,972, respectively)	29,298		30,311
Other	44,802		37,418
Total other assets	1,303,241		1,290,398
TOTAL ASSETS	$	7,582,122	$	6,959,578
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	124,331	$	107,969
Accrued payroll	24,123		23,502
Accrued interest	52,577		50,538
Accrued taxes	44,256		41,614
Regulatory liabilities	44,964		39,972
Refundable deposits from generators for transmission network upgrades	2,534		10,376
Debt maturing within one year	395,334		175,000
Other	31,034		14,043
Total current liabilities	719,153		463,014
Accrued pension and postretirement liabilities	61,609		69,562
Deferred income taxes	735,426		642,051
Regulatory liabilities	254,788		160,070
Refundable deposits from generators for transmission network upgrades	18,077		9,384
Other	23,075		17,354
Long-term debt	4,060,923		3,928,586
Commitments and contingent liabilities (Notes 4 and 16)
STOCKHOLDERS’ EQUITY
Common stock, without par value, 300,000,000 shares authorized, 152,699,077 and 155,140,967 shares issued and outstanding at December 31, 2015 and 2014, respectively	829,211		923,191
Retained earnings	875,595		741,550
Accumulated other comprehensive income	4,265		4,816
Total stockholders’ equity	1,709,071		1,669,557
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	7,582,122	$	6,959,578

See notes to consolidated financial statements.

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ITC HOLDINGS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS



	Year Ended December 31,
(In thousands, except per share data)	2015			2014			2013
OPERATING REVENUES	$	1,044,768		$	1,023,048		$	941,272
OPERATING EXPENSES
Operation and maintenance	113,123			111,623			112,821
General and administrative	144,919			115,031			149,109
Depreciation and amortization	144,672			128,036			118,596
Taxes other than income taxes	82,354			76,534			65,824
Other operating income and expense — net	(1,017		)	(1,005		)	(1,139		)
Total operating expenses	484,051			430,219			445,211
OPERATING INCOME	560,717			592,829			496,061
OTHER EXPENSES (INCOME)
Interest expense — net	203,779			186,636			168,319
Allowance for equity funds used during construction	(28,075		)	(20,825		)	(30,159		)
Loss on extinguishment of debt	—			29,205			—
Other income	(2,071		)	(1,103		)	(1,038		)
Other expense	3,207			4,511			6,571
Total other expenses (income)	176,840			198,424			143,693
INCOME BEFORE INCOME TAXES	383,877			394,405			352,368
INCOME TAX PROVISION	141,471			150,322			118,862
NET INCOME	$	242,406		$	244,083		$	233,506

Basic earnings per common share	$	1.57		$	1.56		$	1.49
Diluted earnings per common share	$	1.56		$	1.54		$	1.47
Dividends declared per common share	$	0.700		$	0.610		$	0.535

See notes to consolidated financial statements.

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ITC HOLDINGS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME



	Year Ended December 31,
(In thousands)	2015			2014			2013
NET INCOME	$	242,406		$	244,083		$	233,506
OTHER COMPREHENSIVE (LOSS) INCOME
Derivative instruments, net of tax (Note 13)	(375		)	(1,479		)	24,304
Available-for-sale securities, net of tax (Note 13)	(176		)	(32		)	71
TOTAL OTHER COMPREHENSIVE (LOSS) INCOME, NET OF TAX	(551		)	(1,511		)	24,375
TOTAL COMPREHENSIVE INCOME	$	241,855		$	242,572		$	257,881

See notes to consolidated financial statements.

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ITC HOLDINGS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN

STOCKHOLDERS’ EQUITY



									Accumulated
									Other			Total
	Common Stock					Retained			Comprehensive			Stockholders’
	Shares		Amount			Earnings			Income (Loss)			Equity
(In thousands, except share and per share data)
BALANCE, DECEMBER 31, 2012	156,745,542		$	989,334		$	443,569		$	(18,048	)	$	1,414,855
Net income	—		—			233,506			—			233,506
Repurchase and retirement of common stock	(163,320	)	(4,885		)	—			—			(4,885		)
Dividends declared on common stock ($0.535 per share)	—		—			(84,129		)	—			(84,129		)
Stock option exercises	499,014		8,165			—			—			8,165
Shares issued under the Employee Stock Purchase Plan	77,097		1,877			—			—			1,877
Issuance of restricted stock	384,576		—			—			—			—
Forfeiture of restricted stock	(42,114	)	—			24			—			24
Share-based compensation, net of forfeitures	—		15,642			—			—			15,642
Tax benefit for excess tax deductions of share-based compensation	—		4,302			—			—			4,302
Other comprehensive income, net of tax (Note 13)	—		—			—			24,375			24,375
BALANCE, DECEMBER 31, 2013	157,500,795		$	1,014,435		$	592,970		$	6,327		$	1,613,732
Net income	—		—			244,083			—			244,083
Repurchase and retirement of common stock	(3,673,226	)	(134,284		)	—			—			(134,284		)
Dividends declared on common stock ($0.610 per share)	—		—			(95,595		)	—			(95,595		)
Stock option exercises	1,011,750		18,650			—			—			18,650
Shares issued under the Employee Stock Purchase Plan	69,230		2,063			—			—			2,063
Issuance of restricted stock	321,139		—			—			—			—
Forfeiture of restricted stock	(88,721	)	—			92			—			92
Share-based compensation, net of forfeitures	—		14,560			—			—			14,560
Tax benefit for excess tax deductions of share-based compensation	—		7,767			—			—			7,767
Other comprehensive loss, net of tax (Note 13)	—		—			—			(1,511		)	(1,511		)
BALANCE, DECEMBER 31, 2014	155,140,967		$	923,191		$	741,550		$	4,816		$	1,669,557
Net income	—		—			242,406			—			242,406
Repurchase and retirement of common stock	(4,201,847	)	(137,081		)	—			—			(137,081		)
Dividends declared ($0.700 per share)	—		—			(108,425		)	—			(108,425		)
Stock option exercises	1,203,376		11,352			—			—			11,352
Shares issued under the Employee Stock Purchase Plan	76,041		2,283			—			—			2,283
Issuance of restricted stock	259,039		—			—			—			—
Forfeiture of restricted stock	(58,209	)	—			64			—			64
Issuance of performance shares	287,464		—			—			—			—
Forfeiture of performance shares	(7,754	)	—			—			—			—
Share-based compensation, net of forfeitures	—		17,609			—			—			17,609
Tax benefit for excess tax deductions of share-based compensation	—		11,707			—			—			11,707
Other comprehensive loss, net of tax (Note 13)	—		—			—			(551		)	(551		)
Other	—		150			—			—			150
BALANCE, DECEMBER 31, 2015	152,699,077		$	829,211		$	875,595		$	4,265		$	1,709,071

See notes to consolidated financial statements.

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ITC HOLDINGS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS



	Year Ended December 31,
(In 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
Allowance for equity funds used during construction	(28,075		)	(20,825		)	(30,159		)
Loss on extinguishment of debt	—			29,205			—
Other	22,031			17,697			17,864
Changes in assets and liabilities, exclusive of changes shown separately:
Accounts receivable	(501		)	(11,869		)	(16,312		)
Inventory	5,140			1,094			5,371
Prepaid and other current assets	(3,214		)	5,089			16,891
Accounts payable	(7,263		)	(19,061		)	17,638
Accrued payroll	463			525			1,619
Accrued interest	2,039			(2,511		)	8,341
Accrued taxes	14,783			19,756			6,113
Tax benefit on the excess tax deduction of share-based compensation	(11,707		)	(7,767		)	(4,302		)
Other current liabilities	5,587			(2,314		)	1,630
Estimated potential refund related to return on equity complaints	120,197			47,780			—
Other non-current assets and liabilities, net	25,355			(13,697		)	7,669
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		)
Proceeds from sale of marketable securities	673			495			20,844
Purchases of marketable securities	(10,422		)	(6,091		)	(22,250		)
Other	(5,456		)	4,040			(3,294		)
Net cash used in investing activities	(699,345		)	(734,701		)	(826,288		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	225,000			798,664			933,025
Borrowings under revolving credit agreements	2,832,100			1,660,000			1,090,100
Borrowings under term loan credit agreements	200,000			110,000			675,000
Net issuance of commercial paper, net of discount	94,630			—			—
Retirement of long-term debt — including extinguishment of debt costs	(175,000		)	(298,625		)	(452,000		)
Repayments of revolving credit agreements	(2,825,000		)	(1,618,400		)	(1,146,700		)
Repayments of term loan credit agreements	—			(189,000		)	(635,000		)
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 generators for transmission network upgrades	12,956			5,833			32,281
Repayment of refundable deposits from generators for transmission network upgrades	(12,025		)	(28,683		)	(38,236		)
Repurchase and retirement of common stock	(137,081		)	(134,284		)	(4,885		)
Tax benefit on the excess tax deduction of share-based compensation	11,707			7,767			4,302
Advance for forward contract of accelerated share repurchase program	—			(20,000		)	—
Return of unused advance for forward contract of accelerated share repurchase program	—			20,000			—
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

See notes to consolidated financial statements.

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ITC HOLDINGS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. GENERAL

ITC Holdings Corp. (“ITC Holdings,” and together with its subsidiaries, “we,” “our” or “us”) and its subsidiaries are engaged in the transmission of electricity in the United States. Through our operating subsidiaries, ITCTransmission, METC, ITC Midwest and ITC Great Plains (together, 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 allow new generating resources to interconnect to our transmission systems. We also are pursuing transmission development projects not within our existing systems, which are intended to improve overall grid reliability, lower electricity congestion and facilitate interconnections of new generating resources, as well as enhance competitive wholesale electricity markets.

Our Regulated Operating Subsidiaries are independent electric transmission utilities, with rates regulated by the FERC and established on a cost-of-service model. ITCTransmission’s service area is located in southeastern Michigan, while METC’s service area covers approximately two-thirds of Michigan’s Lower Peninsula and is contiguous with ITCTransmission’s service area. ITC Midwest’s service area is located in portions of Iowa, Minnesota, Illinois and Missouri and ITC Great Plains currently owns assets located in Kansas and Oklahoma. The Midcontinent Independent System Operator, Inc. (“MISO”) bills and collects revenues from ITCTransmission, METC and ITC Midwest (“MISO Regulated Operating Subsidiaries”) customers. The Southwest Power Pool, Inc. (“SPP”) bills and collects revenue from ITC Great Plains customers.

2. SIGNIFICANT ACCOUNTING POLICIES

A summary of the major accounting policies followed in the preparation of the accompanying consolidated financial statements, which conform to accounting principles generally accepted in the United States of America (“GAAP”), is presented below:

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

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

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

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

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Consolidated Statements of Cash Flows — The following table presents certain supplementary cash flows information for the years ended December 31, 2015, 2014 and 2013:



	Year Ended December 31,
(In thousands)	2015		2014		2013
Supplementary cash flows information:
Interest paid (net of interest capitalized)	$	191,041	$	185,288	$	155,112
Income taxes paid — net	55,722		44,524		20,092
Supplementary non-cash investing and financing activities:
Additions to property, plant and equipment and other long-lived assets (a)	$	110,354	$	90,949	$	68,276
Allowance for equity funds used during construction	28,075		20,825		30,159

____________________________


(a)	Amounts consist of current liabilities for construction labor and materials that have not been included in investing activities. These amounts have not been paid for as of December 31, 2015, 2014 or 2013, respectively, but have been or will be included as a cash outflow from investing activities for expenditures for property, plant and equipment when paid.

Excess tax benefits are recognized as an addition to common stock pursuant to the share-based compensation accounting standards. Cash retained as a result of those excess tax benefits are presented in the statement of cash flows as cash inflows from financing activities and cash outflows from operating activities.

Accounts Receivable — We recognize losses for uncollectible accounts based on specific identification of any such items. As of December 31, 2015 and 2014, we did not have an accounts receivable reserve.

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

Property, Plant and Equipment — Depreciation and amortization expense on property, plant and equipment was $135.5 million, $118.9 million and $109.4 million for 2015, 2014 and 2013, respectively.

Property, plant and equipment in service at our Regulated Operating Subsidiaries is stated at its original cost when first devoted to utility service. The gross book value of assets retired less salvage proceeds is charged to accumulated depreciation. The provision for depreciation of transmission assets is a significant component of our Regulated Operating Subsidiaries’ cost of service under FERC-approved rates. Depreciation is computed over the estimated useful lives of the assets using the straight-line method for financial reporting purposes and accelerated methods for income tax reporting purposes. The composite depreciation rate for our Regulated Operating Subsidiaries included in our consolidated statements of operations was 2.1%, 2.1% and 2.2% for 2015, 2014 and 2013, respectively. The composite depreciation rates include depreciation primarily on transmission station equipment, towers, poles and overhead and underground lines that have a useful life ranging from 48 to 60 years. The portion of depreciation expense related to asset removal costs is added to regulatory liabilities or deducted from regulatory assets and removal costs incurred are deducted from regulatory liabilities or added to regulatory assets. Our Regulated Operating Subsidiaries capitalize to property, plant and equipment an allowance for the cost of equity and borrowings used during construction (“AFUDC”) in accordance with FERC regulations. AFUDC represents the composite cost incurred to fund the construction of assets, including interest expense and a return on equity capital devoted to construction of assets. The AFUDC debt of $6.8 million, $5.1 million and $8.0 million was a reduction to interest expense for 2015, 2014 and 2013, respectively. Certain projects at ITC Great Plains have been granted an incentive to include construction work in progress balances in rate base and we do not record AFUDC on those projects.

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

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

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

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

Our investments in transmission facilities are recorded to property, plant and equipment, and are recorded net of any contribution in aid of construction. Contributions in aid of construction of $17.4 million, $19.7 million and $2.6 million were recorded as reductions to property, plant and equipment during the years ended December 31, 2015, 2014 or 2013, respectively, and are included as reductions of expenditures for property, plant and equipment in our consolidated statements of cash flows when received. We also receive refundable deposits from the generator for certain investment in network upgrade facilities in advance of construction, which are recorded to current or non-current liabilities depending on the expected refund date.

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

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

Goodwill — Under the FASB standards, goodwill is not subject to amortization. However, goodwill is subject to fair value-based rules for measuring impairment, and a resulting write-down, if any, is to be reflected in operating expense. We have goodwill recorded relating to our acquisitions of ITCTransmission and METC and ITC Midwest’s acquisition of the IP&L transmission assets. These accounting standards require that goodwill be reviewed at the reporting unit level at least annually for impairment and whenever facts or circumstances indicate that the value of goodwill may be impaired. In order to perform these impairment tests, we compare the fair value of our reporting units 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 as well as consider estimates of market-based valuation multiples for companies within the peer group of our reporting units.

We completed our annual goodwill impairment test for our reporting units as of October 1, 2015 and determined that no impairment exists. There were no events subsequent to October 1, 2015 that indicated impairment of our goodwill. Our intangible assets have finite lives and are amortized over their useful lives. Refer to Note 6 for additional discussion on our goodwill and intangible assets.

Deferred Financing Fees and Discount or Premium on Debt — The costs related to the issuance of long-term debt are recorded to deferred financing fees and amortized over the life of the debt issue. The debt discount or premium related to the issuance of long-term debt is recorded to long-term debt and amortized over the life of the debt issue. We recorded $4.2 million, $4.1 million and $4.1 million to interest expense for

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the amortization of deferred financing fees and debt discounts during the years ended December 31, 2015, 2014 and 2013, respectively.

Asset Retirement Obligations — We comply with the standards set forth by the FASB for asset retirement obligations. As defined in the standards, a conditional asset retirement obligation is a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within our control. We have identified conditional asset retirement obligations primarily associated with the removal of equipment containing polychlorinated biphenyls (“PCBs”) and asbestos. We record a liability at fair value for a legal asset retirement obligation in the period in which it is incurred. When a new legal obligation is recorded, we capitalize the costs of the liability by increasing the carrying amount of the related long-lived asset. We accrete the liability to its present value each period and depreciate the capitalized cost over the useful life of the related asset. At the end of the asset’s useful life, we settle the obligation for its recorded amount. The standards for asset retirement obligations applied to our Regulated Operating Subsidiaries require us to recognize regulatory assets for the timing differences between the incurred costs to settle our legal asset retirement obligations and the recognition of such obligations under the standards set forth by the FASB. There were no significant changes to our asset retirement obligations in 2015. Our asset retirement obligations as of December 31, 2015 and 2014 of $5.4 million and $5.9 million, respectively, are included in other liabilities.

Financial Instruments — We comply with the standards set forth by the FASB for derivatives and hedging in accounting for financial instruments. For derivative instruments that have been designated and qualify as hedges of the exposure to variability in expected future cash flows, the gain or loss on the derivative is initially reported as a component of other comprehensive income (loss) and reclassified to the consolidated statement of operations when the underlying hedged transaction affects net income. Any hedge ineffectiveness is recognized in net income immediately at the time the gain or loss on the derivative instruments is calculated. Refer to Note 8 for additional discussion regarding derivative instruments.

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

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

The cost-based formula rate templates at our Regulated Operating Subsidiaries include a true-up mechanism, whereby they compare their actual revenue requirements to their billed revenues for each year to determine any over- or under-collection of revenue requirements and record a revenue accrual or deferral for the difference. Refer to Note 4 under “Cost-Based Formula Rates with True-Up Mechanism” for a discussion of our revenue accounting under our cost-based formula rate templates.

Share-Based Payment — We have a Second Amended and Restated 2006 Long-Term Incentive Plan (“2006 LTIP”) and a 2015 Long-Term Incentive Plan (“2015 LTIP”), pursuant to which various share-based awards are granted, including options, restricted stock and performance shares. Compensation cost is recorded over the expected vesting period for restricted stock awards that are expected to vest based on their fair value at grant date. We recognize compensation cost for performance shares that are expected to vest based on their fair value at grant date over the expected vesting period. However, the compensation cost for the portion of the performance share awards subject to an adjusted diluted earnings per share growth condition is recognized based on the probable payout (net of any estimated forfeitures), which is reassessed each reporting period and subject to change. Compensation cost is recorded for stock options that are expected to vest based on their fair value at grant date, and amortized on a straight-line basis over the requisite service period and not for each separately vesting portion of the award. For certain stock option awards, expense is recognized in the period when the service condition is met upon retirement eligibility.

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The grant date is the date at which our commitment to issue share-based awards to an employee or a director arises, which is generally the later of the board approval date or the date of hire or promotion of the employee.

We also have an Employee Stock Purchase Plan (“ESPP”), which is a compensatory plan. Compensation cost is recorded based on the fair value of the purchase options at the grant date, which corresponds to the first day of each purchase period, and is amortized over the purchase period.

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

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

The accounting standards for uncertainty in income taxes prescribe a recognition threshold and a measurement attribute for tax positions taken, or expected to be taken, in a tax return that may not be sustainable. As of December 31, 2015, we did not have any uncertain income tax positions.

We file income tax returns with the Internal Revenue Service and with various state and city jurisdictions. We are no longer subject to U.S. federal tax examinations for tax years 2011 and earlier. State and city jurisdictions that remain subject to examination range from tax years 2011 to 2014. In the event we are assessed interest or penalties by any income tax jurisdictions, interest and penalties would be recorded as interest expense and other expense, respectively, in our consolidated statements of operations.

3. RECENT ACCOUNTING PRONOUNCEMENTS

Revenue Recognition

In May 2014, the FASB issued authoritative guidance requiring entities to apply a new model for recognizing revenue from contracts with customers. The guidance will supersede the current revenue recognition guidance and require entities to evaluate their revenue recognition arrangements using a five-step model to determine when a customer obtains control of a transferred good or service. The guidance is effective for annual reporting periods beginning after December 15, 2017 and may be adopted using a full or modified retrospective application. We do not expect the guidance to have a material impact on our consolidated results of operations, cash flows, or financial position.

Going Concern

In August 2014, the FASB issued authoritative guidance on (1) how to perform a going concern assessment and (2) when going concern disclosures are required under GAAP. The guidance extends the responsibility for performing a going concern assessment to company management; previously, this requirement existed only in auditing literature. The standard is expected to enhance the timeliness, clarity and consistency of going concern disclosures. The guidance is effective for the annual period ending after December 15, 2016, and for interim periods and annual periods thereafter. Early application is permitted. We do not expect the standard to have a material impact on our consolidated financial statements, including our disclosures.

Amendments to the Consolidation Analysis

In February 2015, the FASB issued authoritative guidance that amends the variable interest entity consolidation analysis under GAAP. The new standard was issued to improve targeted areas of consolidation guidance. Although the FASB’s deliberations were largely focused on the investment management industry, the standard is applicable for reporting entities across industries. Specifically, the guidance amends the consolidation analysis for limited partnerships, clarifies when fees paid to a decision maker should be a factor in the consolidation analysis and amends how variable interests held by related parties affect consolidation. The guidance is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2015. Early application is permitted. We do not expect the standard to have a material impact on our consolidated financial statements.

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Amendment to the Balance Sheet Presentation of Debt Issuance Costs

In April 2015, the FASB issued authoritative guidance that amends the balance sheet presentation of debt issuance costs. This new standard requires debt issuance costs to be shown as a direct deduction from the carrying amount of the related debt, consistent with debt discounts. The guidance is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2015 and will be applied retrospectively. Early adoption is permitted. Upon transition, an entity is required to comply with the applicable disclosures for a change in an accounting principle. We are currently assessing the impact this guidance may have on our consolidated statements of financial position and disclosures. The standard will not impact our consolidated statements of operations or cash flows.

Balance Sheet Classification of Deferred Taxes

In November 2015, the FASB issued authoritative guidance which simplifies the presentation of deferred income taxes by requiring entities to net deferred tax assets and deferred tax liabilities and present as non-current in a classified balance sheet. Though the guidance is not effective until annual periods beginning after December 15, 2016 (and interim periods within those years), we elected to early adopt the guidance as of this Form 10-K. In addition, we applied the requirements retrospectively and therefore comparative balance sheet amounts have been adjusted. We have accounted for this as a change in accounting principle that is required based on a change in the authoritative accounting guidance. This standard did not impact our consolidated statements of operations or cash flows. Refer to Note 10 for more information on the balance sheet impacts of the change, including the quantitative effects of the change on prior balance sheets presented.

4. REGULATORY MATTERS

Order on Formula Rate Protocols

In 2012, the FERC issued an order initiating a proceeding pursuant to Section 206 of the FPA to determine whether the formula rate protocols under the MISO Tariff are sufficient to ensure just and reasonable rates. Our MISO Regulated Operating Subsidiaries were named in the order. In May 2013, the FERC issued an order that determined the formula rate protocols are insufficient to ensure just and reasonable rates and directed MISO and its member transmission owners (“TOs”) to file revised formula rate protocols. In September 2013, MISO and its TOs, including our MISO Regulated Operating Subsidiaries, filed revised formula rate protocols, which require our MISO Regulated Operating Subsidiaries to provide additional information for certain aspects of the formula rates used to calculate their respective annual revenue requirements. In March 2014, the FERC issued an order conditionally accepting MISO and its TOs’ September 2013 filing and required a further compliance filing, which MISO and its TOs made in May 2014. On January 22, 2015, the FERC conditionally accepted the May 2014 compliance filing, subject to a further compliance filing, which was made on February 13, 2015. On August 21, 2015, the FERC issued an order accepting the February 13, 2015 compliance filing, effective January 2014. We do not expect these revised formula rate protocols to materially impact our consolidated results of operations, cash flows or financial condition.

Rate of Return on Equity and Capital Structure Complaints

See “Rate of Return on Equity and Capital Structure Complaints” in Note 16 for a discussion of the complaints.

Cost-Based Formula Rate Templates with True-Up Mechanism

The transmission revenue requirements at our Regulated Operating Subsidiaries are set annually, using FERC-approved formula rate templates (“formula rate templates”), and remain in effect for a one-year period. By completing their formula rate templates on an annual basis, our Regulated Operating Subsidiaries are able to make adjustments to reflect changing operational data and financial performance, including the amount of network load on their transmission systems (for our MISO Regulated Operating Subsidiaries), operating expenses and additions to property, plant and equipment when placed in service, among other items. The formula rate templates do not require further action or FERC filings each year, although the template inputs remain subject to legal challenge at the FERC. Our Regulated Operating Subsidiaries will continue to use formula rate templates to calculate their respective annual revenue requirements unless the FERC determines any template to be unjust and unreasonable or another mechanism is determined by the FERC to be just and reasonable. See “Rate of Return on Equity and Capital Structure Complaints” in Note 16 for detail on ROE matters including incentive adders approved by FERC in 2015.

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Our 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 requirements. Revenue is recognized for services provided during each reporting period based on actual revenue requirements calculated using the formula rate templates. Our Regulated Operating Subsidiaries accrue or defer revenues to the extent that the actual revenue requirement for the reporting period is higher or lower, respectively, than the amounts billed relating to that reporting period. The amount of accrued or deferred revenues is reflected in future revenue requirements and thus flows through to customer bills within two years under the provisions of the formula rate templates.

The net changes in regulatory assets and liabilities associated with our Regulated Operating Subsidiaries’ formula rate revenue accruals and deferrals, including accrued interest, were as follows during the year ended December 31, 2015:



(In thousands)	Total
Net regulatory liability as of December 31, 2014	$	(56,103	)
Net refund of 2013 revenue deferrals and accruals, including accrued interest	35,156
Net revenue accrual for the year ended December 31, 2015	19,876
Net accrued interest payable for the year ended December 31, 2015	(1,493		)
Net regulatory liability as of December 31, 2015	$	(2,564	)

Regulatory assets and liabilities associated with our Regulated Operating Subsidiaries’ formula rate revenue accruals and deferrals, including accrued interest, are recorded in the consolidated statements of financial position at December 31, 2015 as follows:



(In thousands)	Total
Current assets	$	14,736
Non-current assets	25,670
Current liabilities	(36,639		)
Non-current liabilities	(6,331		)
Net regulatory liability as of December 31, 2015	$	(2,564	)

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

In May 2013, ITC Great Plains made a filing with the FERC, under Section 205 of the FPA, to recover start-up, development and pre-construction expenses, including associated debt and equity carrying charges, in future rates. These expenses included certain costs incurred by ITC Great Plains for the Kansas Electric Transmission Authority (“KETA”) Project and the Kansas V-Plan Project prior to 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 the FERC. On December 18, 2015, the FERC issued an order accepting the uncontested settlement agreement. As of December 31, 2015, we had a total of $12.6 million (net of accumulated amortization of $1.0 million) of regulatory assets for these expenses, including the associated carrying charges. ITC Great Plains has included the unamortized balance of the regulatory assets in its rate base and commenced amortization over a 10-year period during the second quarter of 2015. The amortization expense is recorded to general and administrative expenses and will be recovered through ITC Great Plains’ cost-based formula rate template.

The start-up, development and pre-construction regulatory assets began accruing carrying charges in March 2009, at a rate equivalent to ITC Great Plains’ weighted average cost of capital, adjusted annually based on ITC Great Plains’ actual weighted average cost of capital calculated in its formula rate template for that year, and continued until the regulatory assets were included in rate base. The equity component of these carrying charges including applicable taxes, totaling $9.9 million as of December 31, 2015, is not recorded for GAAP accounting and reporting as the equity return does not meet the recognition criteria of incurred costs eligible for deferral under GAAP.

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MISO Funding Policy for Generator Interconnections

On June 18, 2015, FERC issued an order initiating a proceeding, pursuant to Section 206 of the FPA, to examine MISO’s funding policy for generator interconnections, which allows a transmission owner to unilaterally elect to fund network upgrades and recover such costs from the interconnection customer. In this order, FERC suggested the MISO funding policy be revised to require mutual agreement between the interconnection customer and transmission owner to utilize the election to fund network upgrades. On July 20, 2015, MISO and its TOs filed a request for a rehearing of the FERC order to examine MISO’s funding policy for generator interconnections, which was subsequently denied by FERC on December 29, 2015. On January 8, 2016, MISO made a compliance filing to revise its funding policy to adopt the FERC suggestion to require mutual agreement between the customer and TO, with an effective date of June 24, 2015. We do not expect the resolution of this proceeding to have a material impact on our consolidated results of operations, cash flows or financial condition.

MISO Formula Rate Template Modifications Filing

On October 30, 2015, our MISO Regulated Operating Subsidiaries requested modifications, pursuant to Section 205 of the FPA, to certain aspects of their respective formula rate templates which included, among other things, changes to ensure that various income tax items are computed correctly for purposes of determining their revenue requirements. Our MISO Regulated Operating Subsidiaries requested an effective date of January 1, 2016 for the proposed template changes. On December 30, 2015, the FERC conditionally accepted the formula rate template modifications and required a further compliance filing, which was made on February 8, 2016. 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. In 2015, our MISO Regulated Operating Subsidiaries recognized a refund liability for the excess amounts recovered for all historical periods through December 31, 2015, which resulted in a reduction in revenues of $9.5 million 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.

ITC Midwest’s Rate Discount

As part of the orders by the Iowa Utility Board and the Minnesota Public Utilities Commission approving ITC Midwest’s asset acquisition, ITC Midwest agreed to provide a rate discount of $4.1 million per year to its customers for eight years, beginning in the first year customers experience an increase in transmission charges following the consummation of the ITC Midwest asset acquisition. Beginning in 2009 and extending through 2016, ITC Midwest’s net revenue requirement was or will be reduced by $4.1 million for each year. The rate discount is recognized in revenues when we provide the service and charge the reduced rate that includes the rate discount.

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5. REGULATORY ASSETS AND LIABILITIES

Regulatory Assets

The following table summarizes the regulatory asset balances at December 31, 2015 and 2014:



(In thousands)	2015		2014
Regulatory Assets:
Current:
Revenue accruals (including accrued interest of $265 and $120 as of December 31, 2015 and 2014, respectively) (a)	$	14,736	$	5,393
Non-current:
Revenue accruals (including accrued interest of $153 and $75 as of December 31, 2015 and 2014, respectively) (a)	25,670		12,387
ITCTransmission ADIT Deferral (net of accumulated amortization of $38,886 and $35,856 as of December 31, 2015 and 2014, respectively)	21,716		24,746
METC ADIT Deferral (net of accumulated amortization of $21,228 and $18,869 as of December 31, 2015 and 2014, respectively)	21,228		23,587
METC Regulatory Deferrals (net of accumulated amortization of $6,943 and $6,172 as of December 31, 2015 and 2014, respectively)	8,486		9,257
Income taxes recoverable related to AFUDC equity	103,465		87,168
ITC Great Plains start-up, development and pre-construction (b)	12,577		14,054
Pensions and postretirement	18,981		34,151
Income taxes recoverable related to implementation of the Michigan Corporate Income Tax	8,869		8,869
Accrued asset removal costs	12,117		7,337
Other	267		2,156
Total non-current	233,376		223,712

Total	$	248,112	$	229,105

____________________________


(a)	Refer to discussion of revenue accruals in Note 4 under “Cost-Based Formula Rates with True-Up Mechanism.” Our Regulated Operating Subsidiaries do not earn a return on the balance of these regulatory assets, but do accrue interest carrying costs, which are subject to rate recovery along with the principal amount of the revenue accrual.


(b)	Refer to discussion of ITC Great Plains start-up, development and pre-construction in Note 4 under “ITC Great Plains Start-Up, Development and Pre-Construction Regulatory Assets.”

ITCTransmission ADIT Deferral

The carrying amount of the ITCTransmission Accumulated Deferred Income Tax (“ADIT”) Deferral is the remaining unamortized balance of the portion of ITCTransmission’s purchase price in excess of the fair value of net assets acquired approved for inclusion in future rates by the FERC. ITCTransmission earns a return on the remaining unamortized balance of this regulatory asset that is included in rate base. The original amount recorded for this regulatory asset of $60.6 million is recognized in rates and amortized on a straight-line basis over 20 years. ITCTransmission recorded amortization expense of $3.0 million annually during 2015, 2014 and 2013, which is included in depreciation and amortization and recovered through ITCTransmission’s cost-based formula rate template.

METC ADIT Deferral

The carrying amount of the METC ADIT Deferral is the remaining unamortized balance of the portion of METC’s purchase price in excess of the fair value of net assets acquired from Consumers Energy approved for inclusion in future rates by the FERC. The original amount recorded for this regulatory asset of $42.5 million is recognized in rates and amortized on a straight-line basis over 18 years beginning January 1, 2007. METC earns a return on the remaining unamortized balance of this regulatory asset that is included in rate base. METC recorded amortization expense of $2.4 million annually during 2015, 2014 and 2013, which is included in depreciation and amortization and recovered through METC’s cost-based formula rate template.

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METC Regulatory Deferrals

METC has deferred, as a regulatory asset, depreciation and related interest expense associated with new transmission assets placed in service from January 1, 2001 through December 31, 2005 that were included on METC’s balance sheet at the time Michigan Transco Holdings, LLC (“MTH”) acquired METC from Consumers Energy (the “METC Regulatory Deferrals”). The original amount recorded for this regulatory asset of $15.4 million is recognized in rates and amortized over 20 years beginning January 1, 2007. METC earns a return on the remaining unamortized balance of this regulatory asset that is included in rate base. METC recorded amortization expense of $0.8 million annually during 2015, 2014 and 2013, which is included in depreciation and amortization and recovered through METC’s cost-based formula rate template.

Income Taxes Recoverable Related to AFUDC Equity

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

Pensions and Postretirement

Accounting standards for defined benefit pension and other postretirement plans for rate-regulated entities allow for amounts that otherwise would have been charged and/or credited to AOCI to be recorded as a regulatory asset or liability. As the unrecognized amounts recorded to this regulatory asset are recognized, expenses will be recovered from customers in future rates under our cost based formula rates. Our Regulated Operating Subsidiaries do not earn a return on the balance of this regulatory asset.

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

In May 2011, the Michigan Business Tax (“MBT”) was repealed and replaced with the Michigan Corporate Income Tax (“CIT”), effective January 1, 2012. Under the CIT, we are taxed at a rate of 6.0% on federal taxable income attributable to our operations in the state of Michigan, subject to certain adjustments. In addition to the traditional income tax, the MBT had also included a modified gross receipts tax that allowed for deductions and credits for certain activities, none of which are part of the CIT. The change in Michigan tax law required us in 2011 to remove deferred income tax balances recognized under the MBT and establish new deferred income tax balances under the CIT, and the net result was incremental deferred state income tax liabilities at both ITCTransmission and METC. Under our cost-based formula rate, the future taxes receivable as a result of the tax law change has resulted in the recognition of a regulatory asset, which will be collected from customers for the 23-year period and the 32-year period for ITCTransmission and METC, respectively, beginning in 2016. ITCTransmission and METC do not earn a return on the balance of this regulatory asset and the related net deferred tax liabilities do not reduce rate base.

Accrued Asset Removal Costs

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

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Regulatory Liabilities

The following table summarizes the regulatory liability balances at December 31, 2015 and 2014:



(In thousands)	2015		2014
Regulatory Liabilities:
Current:
Revenue deferrals (including accrued interest of $1,698 and $1,853 as of December 31, 2015 and 2014, respectively) (a)	$	36,639	$	39,972
Refund related to the formula rate template modifications (including accrued interest of $864 as of December 31, 2015) (b)	8,154		—
Other	171		—
Total current	44,964		39,972
Non-current:
Revenue deferrals (including accrued interest of $101 and $541 as of December 31, 2015 and 2014, respectively) (a)	6,331		33,911
Accrued asset removal costs	70,233		70,705
Refund related to the formula rate template modifications (including accrued interest of $36 as of December 31, 2015) (b)	2,270		—
Estimated potential refund related to return on equity complaints (including accrued interest of $5,979 and $870 as of December 31, 2015 and 2014, respectively) (c)	167,977		47,780
Excess state income tax deductions	7,823		7,504
Other	154		170
Total non-current	254,788		160,070

Total	$	299,752	$	200,042

____________________________


(a)	Refer to discussion of revenue deferrals in Note 4 under “Cost-Based Formula Rates with True-Up Mechanism.” Our Regulated Operating Subsidiaries accrue interest on the true-up amounts which will be refunded through rates along with the principal amount of revenue deferrals in future periods.


(b)	Refer to discussion of the refund in Note 4 under “MISO Formula Rate Template Modifications Filing.”


(c)	Refer to discussion of the estimated potential refund in Note 16 under “Rate of Return on Equity and Capital Structure Complaints.”

Accrued Asset Removal Costs

Excess State Income Tax Deductions

We have taken income tax deductions associated with property additions that exceed the tax basis of property, and the unrealized income tax benefits resulting from these deductions are expected to be refunded to customers through future rates when the income tax benefits are realized. This regulatory liability and the related deferred tax assets do not affect rate base.

6. GOODWILL AND INTANGIBLE ASSETS

Goodwill

At December 31, 2015 and 2014, we had goodwill balances recorded at ITCTransmission, METC and ITC Midwest of $173.4 million, $453.8 million and $323.0 million, respectively, which resulted from the ITCTransmission and METC acquisitions and ITC Midwest’s asset acquisition, respectively.

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Intangible Assets

Pursuant to the METC acquisition in October 2006, we have identified intangible assets with finite lives derived from the portion of regulatory assets recorded on METC’s historical FERC financial statements that were not recorded on METC’s historical GAAP financial statements associated with the METC Regulatory Deferrals and the METC ADIT Deferral. The carrying amounts of the intangible asset for the METC Regulatory Deferrals and the METC ADIT Deferral were $21.8 million and $9.4 million, respectively, as of December 31, 2015, and $23.7 million and $10.5 million, respectively, as of December 31, 2014. The amortization periods for the METC Regulatory Deferrals and the METC ADIT Deferral are 20 years and 18 years, respectively, beginning January 1, 2007. METC earns an equity return on the remaining unamortized balance of both intangible assets and recovers the amortization expense through METC’s cost-based formula rate template.

ITC Great Plains has recorded intangible assets for payments made by and obligations of ITC Great Plains to certain TOs to acquire rights, which are required under the SPP tariff to designate ITC Great Plains to build, own and operate projects within the SPP region, including the KETA Project and the Kansas V-Plan Project. The carrying amount of these intangible assets was $14.4 million and $14.6 million (net of accumulated amortization of $1.0 million and $0.7 million, respectively) as of December 31, 2015 and 2014, respectively. The amortization period for these intangible assets is 50 years.

During each of the years ended December 31, 2015, 2014 and 2013, we recognized $3.3 million, $3.3 million and $3.2 million, respectively, of amortization expense of our intangible assets. We expect the annual amortization of our intangible assets that have been recorded as of December 31, 2015 to be as follows:



(In thousands)
2016	$	3,334
2017	3,334
2018	3,334
2019	3,334
2020	3,334
2021 and thereafter	28,932
Total	$	45,602

7. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment — net consisted of the following at December 31, 2015 and 2014:



(In thousands)	2015			2014
Property, plant and equipment
Regulated Operating Subsidiaries:
Property, plant and equipment in service	$	7,085,818		$	6,396,449
Construction work in progress	425,594			391,788
Capital equipment inventory	54,781			68,170
Other	12,550			13,151
ITC Holdings and other	18,609			15,534
Total	7,597,352			6,885,092
Less: Accumulated depreciation and amortization	(1,487,713		)	(1,388,217		)
Property, plant and equipment — net	$	6,109,639		$	5,496,875

Additions to property, plant and equipment in service and construction work in progress during 2015 and 2014 were due primarily for projects to upgrade or replace existing transmission plant to improve the reliability of our transmission systems as well as transmission infrastructure to support generator interconnections and investments that provide regional benefits such as our Multi-Value Projects.

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8. DEBT

The following amounts were outstanding at December 31, 2015 and 2014:



(Amounts in thousands)	2015		2014
ITC Holdings 5.875% Senior Notes, due September 30, 2016 (net of discount of $3 and $6, respectively) (a) (b)	$	139,341	$	139,338
ITC Holdings 6.23% Senior Notes, Series B, due September 20, 2017	50,000		50,000
ITC Holdings 6.375% Senior Notes, due September 30, 2036 (net of discount of $159 and $166, respectively) (a)	200,181		200,174
ITC Holdings 6.05% Senior Notes, due January 31, 2018 (net of discount of $329 and $487, respectively)	384,671		384,513
ITC Holdings 5.50% Senior Notes, due January 15, 2020 (net of discount of $521 and $654, respectively)	199,479		199,346
ITC Holdings 4.05% Senior Notes, due July 1, 2023 (net of discount of $534 and $606, respectively)	249,466		249,394
ITC Holdings 3.65% Senior Notes, due June 15, 2024 (net of discount of $1,124 and $1,258, respectively)	398,876		398,742
ITC Holdings 5.30% Senior Notes, due July 1, 2043 (net of discount of $737 and $763, respectively)	299,263		299,237
ITC Holdings Term Loan Credit Agreement, due September 30, 2016 (b)	161,000		161,000
ITC Holdings Revolving Credit Agreement, due March 28, 2019	137,700		53,500
ITC Holdings Commercial Paper Program (net of discount of $10) (b)	94,990		—
ITCTransmission 6.125% First Mortgage Bonds, Series C, due March 31, 2036 (net of discount of $74 and $79, respectively)	99,926		99,921
ITCTransmission 5.75% First Mortgage Bonds, Series D, due April 1, 2018 (net of discount of $26 and $37, respectively)	99,974		99,963
ITCTransmission 4.625% First Mortgage Bonds, Series E, due August 15, 2043 (net of discount of $422 and $437, respectively)	284,578		284,563
ITCTransmission 4.27% First Mortgage Bonds, Series F, due June 10, 2044	100,000		100,000
ITCTransmission Revolving Credit Agreement, due March 28, 2019	48,300		14,300
METC 5.75% Senior Secured Notes, due December 10, 2015 (b)	—		175,000
METC 5.64% Senior Secured Notes, due May 6, 2040	50,000		50,000
METC 3.98% Senior Secured Notes, due October 26, 2042	75,000		75,000
METC 4.19% Senior Secured Notes, due December 15, 2044	150,000		150,000
METC Term Loan Credit Agreement, due December 7, 2018	200,000		—
METC Revolving Credit Agreement, due March 28, 2019	2,500		—
ITC Midwest 6.15% First Mortgage Bonds, Series A, due January 31, 2038 (net of discount of $388 and $405, respectively)	174,612		174,595
ITC Midwest 7.12% First Mortgage Bonds, Series B, due December 22, 2017	40,000		40,000
ITC Midwest 7.27% First Mortgage Bonds, Series C, due December 22, 2020	35,000		35,000
ITC Midwest 4.60% First Mortgage Bonds, Series D, due December 17, 2024	75,000		75,000
ITC Midwest 3.50% First Mortgage Bonds, Series E, due January 19, 2027	100,000		100,000
ITC Midwest 4.09% First Mortgage Bonds, Series F, due April 30, 2043	100,000		100,000
ITC Midwest 3.83% First Mortgage Bonds, Series G, due April 7, 2055	225,000		—
ITC Midwest Revolving Credit Agreement, due March 28, 2019	72,300		191,200
ITC Great Plains 4.16% First Mortgage Bonds, Series A, due November 26, 2044	150,000		150,000
ITC Great Plains Revolving Credit Agreement, due March 28, 2019	59,100		53,800
Total debt	$	4,456,257	$	4,103,586

____________________________


(a)	The debt obligations were partially retired prior to maturity date through the cash tender offer described below.


(b)	As of December 31, 2015 and 2014, there was $395.3 million and $175.0 million, respectively, of debt included within debt maturing within one year that is classified as a current liability in the consolidated statements of financial position.

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The annual maturities of debt as of December 31, 2015 are as follows:



(In thousands)
2016	$	395,344
2017	90,000
2018	685,000
2019	319,900
2020	235,000
2021 and thereafter	2,735,340
Total	$	4,460,584

ITC Holdings

Commercial Paper Program

On June 8, 2015, ITC Holdings established an ongoing commercial paper program for the issuance and sale of unsecured commercial paper in an aggregate amount not to exceed $400.0 million outstanding at any one time. As of December 31, 2015, ITC Holdings had approximately $95.0 million of commercial paper issued and outstanding under the program, with a weighted-average interest rate of 0.8% and weighted average remaining days to maturity of 6 days. The proceeds from the issuances under the program were used for general corporate purposes, including the repayment of borrowings under ITC Holdings’ revolving credit agreement. The amount outstanding as of December 31, 2015 was classified as debt maturing within one year in the consolidated statements of financial position.

Cash Tender Offer

In May 2014, ITC Holdings commenced a cash tender offer for any and all of the outstanding $255.0 million ITC Holdings 5.875% Senior Notes due September 30, 2016 and $255.0 million ITC Holdings 6.375% Senior Notes due September 30, 2036, under which $115.6 million of the 5.875% Senior Notes and $54.7 million of the 6.375% Senior Notes were validly tendered on May 30, 2014. All of the Senior Notes validly tendered were subsequently retired with the proceeds from the $400.0 million 3.65% Senior Notes described below. ITC Holdings incurred a loss on extinguishment of debt of $29.2 million related to the tender premium, the write-off of deferred debt issuance costs and other related expenses.

Senior Unsecured Notes

On June 4, 2014, ITC Holdings issued $400.0 million aggregate principal amount of 3.65% Senior Notes, due June 15, 2024. The proceeds from the issuance were used for the cash tender offer described above and for general corporate purposes, primarily the repayment of borrowings under the ITC Holdings revolving credit agreement. These ITC Holdings Senior Notes were issued under its 2013 indenture. All issuances of ITC Holdings Senior Notes are unsecured.

ITCTransmission

On June 10, 2014, ITCTransmission issued $75.0 million of the total face amount of $100.0 million of 4.27% First Mortgage Bonds, Series F, due June 10, 2044 (“First Mortgage Bonds, Series F”). ITCTransmission issued the remaining $25.0 million of First Mortgage Bonds, Series F on August 22, 2014. The proceeds from both issuances were used for general corporate purposes, primarily the repayment of borrowings under the ITCTransmission revolving credit agreement. ITCTransmission’s First Mortgage Bonds are issued under its first mortgage and deed of trust and secured by a first mortgage lien on substantially all of its property.

METC

Term Loan Credit Agreements

On December 8, 2015, METC entered into an unsecured, unguaranteed term loan credit agreement due December 7, 2018, under which METC borrowed the maximum of $200.0 million available under the agreement. The proceeds were used to repay the $175.0 million of 5.75% Senior Secured Notes, due December 10, 2015, and for general corporate purposes. The weighted-average interest rate on the borrowing outstanding under this agreement was 1.3% at December 31, 2015.

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On January 31, 2014, METC entered into an unsecured, unguaranteed term loan credit agreement, due February 2, 2015, under which METC borrowed the maximum of $50.0 million available under the agreement. The proceeds were used for general corporate purposes, primarily the repayment of borrowings under the METC revolving credit agreement. This borrowing was repaid in full in the fourth quarter of 2014.

Senior Secured Notes

On December 17, 2014, METC issued $150.0 million of 4.19% Senior Secured Notes, due December 15, 2044. The proceeds were used to repay the $50.0 million of 6.63% Senior Secured Notes, due December 18, 2014, and the $50.0 million borrowed under METC’s term loan credit agreement described above and for general corporate purposes, including the repayment of borrowings under METC’s revolving credit agreement. The METC Senior Secured Notes are issued under its first mortgage indenture and secured by a first mortgage lien on substantially all of its real property and tangible personal property.

ITC Midwest

On April 7, 2015, ITC Midwest issued $225.0 million aggregate principal amount of 3.83% First Mortgage Bonds, Series G, due April 7, 2055. The proceeds from the issuance were used for general corporate purposes, including the repayment of borrowings under ITC Midwest’s revolving credit agreement. ITC Midwest’s First Mortgage Bonds are issued under its first mortgage and deed of trust and secured by a first mortgage lien on substantially all of its property.

ITC Great Plains

First Mortgage Bonds

On November 26, 2014, ITC Great Plains issued $150.0 million of 4.16% First Mortgage Bonds, Series A, due November 26, 2044. The proceeds were used to repay the $100.0 million borrowed under a term loan credit agreement entered into by ITC Great Plains and for general corporate purposes, including the repayment of borrowings under the ITC Great Plains’ revolving credit agreement. ITC Great Plains’ First Mortgage Bonds are issued under its first mortgage and deed of trust and secured by a first mortgage lien on substantially all of its property.

Derivative Instruments and Hedging Activities



Interest Rate Swaps	Notional Amount		Fixed Rate		Original Term	Effective Date
(Amounts in millions)
August 2014 swap	$	25.0	3.217	%	10 years	September 2016
October 2014 swap	25.0		3.075	%	10 years	September 2016
January 2015 swap	25.0		2.301	%	10 years	September 2016
Total	$	75.0

The 10-year term interest rate swaps call for ITC Holdings to receive interest quarterly at a variable rate equal to LIBOR and pay interest semi-annually at various fixed rates effective for the 10-year period beginning September 30, 2016 after the agreements have been terminated. The agreements include a mandatory early termination provision and will be terminated no later than the effective date of the interest rate swaps of September 30, 2016. The interest rate swaps have been determined to be highly effective at offsetting changes in the fair value of the forecasted interest cash flows associated with the expected debt issuance, resulting from changes in benchmark interest rates from the trade date of the interest rate swaps to the issuance date of the debt obligation. ITC Holdings entered into two additional 10-year interest rate swap contracts in February 2016 with notional amounts of $25.0 million each and fixed rates of 1.770% and 1.619%. These additional interest rate swaps

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also manage interest rate risk associated with the expected refinancing of the 5.875% Senior Notes and have terms comparable to the interest rate swaps described above.

As of December 31, 2015, there has been no material ineffectiveness recorded in the consolidated statement of operations. The interest rate swaps qualify for hedge accounting treatment, whereby any gain or loss recognized from the trade date to the effective date for the effective portion of the hedge is recorded net of tax in accumulated other comprehensive income (“AOCI”). This amount will be accumulated and amortized as a component of interest expense over the life of the related forecasted debt issuance. As of December 31, 2015, the fair value of the derivative instruments was an asset of $0.1 million recorded to other current assets and a liability of $3.5 million recorded to other current liabilities. None of the interest rate swaps contain credit-risk-related contingent features. Refer to Note 12 for additional fair value information.

Revolving Credit Agreements

At December 31, 2015, ITC Holdings and its Regulated Operating Subsidiaries had the following unsecured revolving credit facilities available:



(Amounts in millions)	Total Available Capacity		Outstanding Balance (a)		Unused Capacity			Weighted Average Interest Rate on Outstanding Balance		Commitment Fee Rate (b)
ITC Holdings	$	400.0	$	137.7	$	262.3	(c)	1.6%	(d)	0.175	%
ITCTransmission	100.0		48.3		51.7			1.4%	(e)	0.10	%
METC	100.0		2.5		97.5			1.4%	(e)	0.10	%
ITC Midwest	250.0		72.3		177.7			1.4%	(e)	0.10	%
ITC Great Plains	150.0		59.1		90.9			1.4%	(e)	0.10	%
Total	$	1,000.0	$	319.9	$	680.1

____________________________


(a)	Included within long-term debt.


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

(c)

ITC Holdings’ revolving credit agreement may be used for general corporate purposes, including to repay commercial paper issued pursuant to the commercial paper program described above, if necessary. While outstanding commercial paper does not reduce available capacity under ITC Holdings’ revolving credit agreement, the unused capacity under this agreement adjusted for the commercial paper outstanding was $167.3 million as of December 31, 2015.


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


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

Covenants

Our debt instruments contain numerous financial and operating covenants that place significant restrictions on certain transactions, such as incurring additional indebtedness, engaging in sale and lease-back transactions, creating liens or other encumbrances, entering into mergers, consolidations, liquidations or dissolutions, creating or acquiring subsidiaries, selling or otherwise disposing of all or substantially all of our assets and paying dividends. In addition, the covenants require us to meet certain financial ratios, such as maintaining certain debt to capitalization ratios and maintaining certain interest coverage ratios. As of December 31, 2015, we were not in violation of any debt covenant.

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9. EARNINGS PER SHARE

We report both basic and diluted EPS. Our restricted stock contain rights to receive nonforfeitable dividends and thus, are participating securities requiring the two-class method of computing EPS. A reconciliation of both calculations for the years ended December 31, 2015, 2014 and 2013 is presented in the following table (see additional information below under “Stock Split” for the recast share and per share data for the year ended December 31, 2013 as a result of the three-for-one stock split):



	Year Ended December 31,
(In thousands, except share, per share data and percentages)	2015			2014			2013
Numerator:
Net income	$	242,406		$	244,083		$	233,506
Less: dividends declared and paid — common and restricted shares	(108,211		)	(95,503		)	(84,104		)
Undistributed earnings	134,195			148,580			149,402
Percentage allocated to common shares (a)	99.3		%	99.2		%	99.1		%
Undistributed earnings — common shares	133,256			147,391			148,057
Add: dividends declared and paid — common shares	107,520			94,824			83,351
Numerator for basic and diluted earnings per common share	$	240,776		$	242,215		$	231,408
Denominator:
Basic earnings per common share — weighted average common shares outstanding	153,670,087			155,363,848			155,736,384
Incremental shares for stock options, ESPP shares and performance shares — weighted average assumed conversion	1,031,034			1,453,804			1,288,620
Diluted earnings per common share — adjusted weighted average shares and assumed conversion	154,701,121			156,817,652			157,025,004
Per common share net income:
Basic	$	1.57		$	1.56		$	1.49
Diluted	$	1.56		$	1.54		$	1.47

____________________________



(a)	Weighted average common shares outstanding	153,670,087		155,363,848		155,736,384
	Weighted average restricted shares (participating securities)	1,102,051		1,277,128		1,472,967
	Total	154,772,138		156,640,976		157,209,351
	Percentage allocated to common shares	99.3	%	99.2	%	99.1	%

The incremental shares for stock options and the ESPP shares are included in the diluted EPS calculation using the treasury stock method, unless the effect of including them would be anti-dilutive. Additionally, the performance shares discussed in Note 14 are included in the diluted EPS calculation using the treasury stock method when the performance metric is substantively measurable as of the end of the reporting period and has been met under the assumption the end of the reporting period was the end of the performance period. The outstanding stock options, ESPP shares and performance shares and the anti-dilutive stock options and ESPP shares excluded from the diluted EPS calculations were as follows:



	2015	2014	2013
Outstanding stock options, ESPP shares and performance shares (as of December 31)	4,096,910	4,603,292	5,169,828
Anti-dilutive stock options and ESPP shares (for the year ended December 31)	1,056,250	550,178	912,570

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Stock Split

Below are the effects of the stock split on earnings per share for the year ended December 31, 2013:



(In thousands, except per share and share data)	Reported		Adjustment			Adjusted
For the year ended December 31, 2013
Numerator for basic and diluted earnings per common share	$	231,408	$	—		$	231,408
Denominator:
Basic earnings per common share — weighted average common shares	51,912,128		103,824,256			155,736,384
Incremental shares for stock options and employee stock purchase plan	429,540		859,080			1,288,620
Diluted earnings per common share — adjusted weighted average shares and assumed conversion	52,341,668		104,683,336			157,025,004
Per common share net income:
Basic	$	4.46	$	(2.97	)	$	1.49
Diluted	$	4.42	$	(2.95	)	$	1.47

Below are the effects of the stock split on other disclosures included for earnings per share for the year ended December 31, 2013:

Percentage Allocated to Common Shares



	Reported		Adjustment		Adjusted
For the year ended December 31, 2013
Weighted-average common shares outstanding	51,912,128		103,824,256		155,736,384
Weighted-average restricted shares (participating securities)	490,989		981,978		1,472,967
Total	52,403,117		104,806,234		157,209,351
Percentage allocated to common shares	99.1	%	—	%	99.1	%

Outstanding and Anti-dilutive Stock Options and ESPP Shares

The outstanding stock options and the ESPP shares as of December 31, 2013 and the anti-dilutive stock options and ESPP shares excluded from the diluted earnings per share calculations for the year ended December 31, 2013 was as follows:



	Reported	Adjustment	Adjusted
As of and for the year ended December 31, 2013
Outstanding stock options and ESPP shares	1,723,276	3,446,552	5,169,828
Anti-dilutive stock options and ESPP shares	304,190	608,380	912,570

Impacts of the Accelerated Share Repurchase Program

The basic shares outstanding as of December 31, 2015 and 2014 include the impact of the aggregate 7.2 million and 3.6 million shares, respectively, received under the ASR programs described in Note 13.

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10. INCOME TAXES

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



(In thousands)	2015			2014			2013
Income tax expense at 35% statutory rate	$	134,357		$	138,042		$	123,329
State income taxes (net of federal benefit)	13,366			16,054			9,110
AFUDC equity	(8,469		)	(6,201		)	(9,715		)
Entergy Transaction expenses (a)	—			—			(5,614		)
Other — net	2,217			2,427			1,752
Total income tax provision	$	141,471		$	150,322		$	118,862

____________________________


(a)	See Note 17 for discussion of the Entergy Transaction.

Components of the income tax provision were as follows:



(In thousands)	2015		2014		2013
Current income tax expense	$	64,100	$	59,949	$	42,159
Deferred income tax expense	76,833		90,313		76,094
Benefits of operating loss carryforward	538		60		609
Total income tax provision	$	141,471	$	150,322	$	118,862

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

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



(In thousands)	2015			2014
Property, plant and equipment	$	(678,567	)	$	(560,960	)
METC regulatory deferral (a)	(11,629		)	(12,721		)
Acquisition adjustments — ADIT deferrals (a)	(15,300		)	(15,164		)
Goodwill	(147,894		)	(133,138		)
Net revenue accruals and deferrals, including accrued interest (a)	961			22,047
Refund liabilities (a)	70,234			18,878
Pension and postretirement liabilities	18,508			14,196
State income tax NOLs (net of federal benefit)	20,375			20,004
Share-based compensation	13,661			12,211
Other — net	(5,775		)	(7,404		)
Net deferred tax liabilities	$	(735,426	)	$	(642,051	)
Gross deferred income tax liabilities	$	(888,727	)	$	(810,141	)
Gross deferred income tax assets	153,301			168,090
Net deferred tax liabilities	$	(735,426	)	$	(642,051	)

____________________________

(a)Described in Note 5.

We have state income tax net operating losses (“NOLs”) as of December 31, 2015, all of which we expect to use prior to their expiration. Our state income tax NOLs would expire beginning in 2022. In addition to the estimated state income tax NOL deferred tax assets in the table above, we have additional estimated state income tax NOLs of $8.6 million and $7.1 million tax effected, net of federal benefit, as of December 31, 2015 and 2014, respectively, that have not been recognized in the consolidated statements of financial position relating to tax deductions for share-based payment. The accounting standards for share-based payment require that a tax deduction that

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exceeds book value be recognized only if that deduction reduces taxes payable as a result of a realized cash benefit from the deduction.

Balance Sheet Classification of Deferred Taxes

As described in Note 3, we adopted accounting guidance that requires deferred tax assets and deferred tax liabilities to be presented as non-current in our balance sheet and have applied this change to all amounts presented in our consolidated statements of financial position. The following shows the impact of this adoption on our previously reported consolidated statement of financial position as of December 31, 2014:



(In thousands)	Reported		Adjustment			Adjusted
Current assets — Deferred income taxes	$	14,511	$	(14,511	)	$	—
Non-current liabilities — Deferred income taxes	656,562		(14,511		)	642,051

11. RETIREMENT BENEFITS AND ASSETS HELD IN TRUST

Pension Plan Benefits

We have a qualified defined benefit pension plan (“retirement plan”) for eligible employees, comprised of a traditional final average pay plan and a cash balance plan. The traditional final average pay plan is noncontributory, covers select employees and provides retirement benefits based on years of benefit service, average final compensation and age at retirement. The cash balance plan is also noncontributory, covers substantially all employees and provides retirement benefits based on eligible compensation and interest credits. Our funding practice for the retirement plan is to contribute amounts necessary to meet the minimum funding requirements of the Employee Retirement Income Security Act of 1974, plus additional amounts as we determine appropriate. We made contributions of $4.1 million, $3.8 million and $6.9 million to the retirement plan in 2015, 2014 and 2013, respectively. We expect to contribute up to $2.8 million to the retirement plan in 2016.

We also have two supplemental nonqualified, noncontributory, defined benefit pension plans for selected management employees (the “supplemental benefit plans” and collectively with the retirement plan, the “pension plans”). The supplemental benefit plans provide for benefits that supplement those provided by the retirement plan. The obligations under these supplemental benefit plans are included in the pension benefit obligation calculations below. The investments held in trust for the supplemental benefit plans of $35.6 million and $26.5 million at December 31, 2015 and 2014, respectively, are not included in the plan asset amounts presented below, but are included in other assets on our consolidated statement of financial position. For the years ended December 31, 2015, 2014 and 2013, we contributed $9.4 million, $5.1 million and $0.6 million, respectively, to these supplemental benefit plans.

Our investments held for the supplemental benefit plans are classified as available-for-sale securities and the net unrealized loss of $0.2 million through December 31, 2015 and net unrealized gain of $0.1 million through December 31, 2014 were recognized in the accumulated other comprehensive income component of equity.

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



Asset Category	2015		2014
Fixed income securities	50.4	%	48.8	%
Equity securities	49.6	%	51.2	%
Total	100.0	%	100.0	%

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Net periodic benefit cost for the pension plans during 2015, 2014 and 2013 was as follows by component:



(In thousands)	2015			2014			2013
Service cost	$	6,496		$	5,066		$	5,261
Interest cost	3,696			3,603			2,792
Expected return on plan assets	(3,838		)	(3,541		)	(2,868		)
Amortization of prior service credit	(42		)	(42		)	(42		)
Amortization of unrecognized loss	4,243			1,545			2,714
Net pension cost	$	10,555		$	6,631		$	7,857

The following table reconciles the obligations, assets and funded status of the pension plans as well as the presentation of the funded status of the pension plans in the consolidated statements of financial position as of December 31, 2015 and 2014:



(In thousands)	2015			2014
Change in Benefit Obligation:
Beginning projected benefit obligation	$	(95,740	)	$	(73,468	)
Service cost	(6,496		)	(5,066		)
Interest cost	(3,696		)	(3,603		)
Actuarial net gain (loss)	5,869			(14,937		)
Benefits paid	2,747			1,334
Other	128			—
Ending projected benefit obligation	$	(97,188	)	$	(95,740	)
Change in Plan Assets:
Beginning plan assets at fair value	$	56,390		$	48,894
Actual return on plan assets	(129		)	4,851
Employer contributions	4,102			3,822
Benefits paid	(2,108		)	(1,177		)
Other	(128		)	—
Ending plan assets at fair value	$	58,127		$	56,390
Funded status, underfunded	$	(39,061	)	$	(39,350	)
Accumulated benefit obligation:
Retirement plan	$	(49,169	)	$	(48,571	)
Supplemental benefit plans	(40,830		)	(35,962		)
Total accumulated benefit obligation	$	(89,999	)	$	(84,533	)
Amounts recorded as:
Funded Status:
Accrued pension liabilities	$	(45,322	)	$	(44,033	)
Other non-current assets	6,408			4,683
Other current liabilities	(147		)	—
Total	$	(39,061	)	$	(39,350	)
Unrecognized Amounts in Non-current Regulatory Assets:
Net actuarial loss	$	18,724		$	24,868
Prior service credit	66			25
Total	$	18,790		$	24,893

The unrecognized amounts that otherwise would have been charged and/or credited to accumulated other comprehensive income in accordance with the FASB guidance on accounting for retirement benefits are recorded as a regulatory asset on our consolidated statements of financial position as discussed in Note 5. The amounts

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recorded as a regulatory asset represent a net periodic benefit cost to be recognized in our operating income in future periods.

The actuarial net loss in 2014 includes the impact of a change in our mortality assumption, which generally assumes longer life expectancies for plan participants as compared with our prior assumption. Additionally the reduction in our discount rate assumption contributed to the actuarial net loss in 2014. The actuarial net gain in 2015 resulted primarily from an increase in discount rates.

Actuarial assumptions used to determine the benefit obligation for the pension plans at December 31, 2015, 2014 and 2013 are as follows:



	2015	2014	2013
Discount rate	4.01 - 4.44%	3.75 - 4.05%	4.60 - 5.10%
Annual rate of salary increases	4.00%	4.00%	4.00 - 6.00%

Actuarial assumptions used to determine the benefit cost for the pension plans for the years ended December 31, 2015, 2014 and 2013 are as follows:



	2015	2014	2013
Discount rate	3.75 - 4.05%	4.60 - 5.10%	3.70 - 4.45%
Annual rate of salary increases	4.00%	4.00 - 6.00%	5.00 - 6.00%
Expected long-term rate of return on plan assets	6.70%	6.75%	7.00%

At December 31, 2015, the projected benefit payments for the pension plans calculated using the same assumptions as those used to calculate the benefit obligation described above are as follows:



(In thousands)
2016	$	1,716
2017	5,259
2018	5,548
2019	5,878
2020	6,551
2021 through 2025	38,681

Investment Objectives and Fair Value Measurement

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

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

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

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at the beginning of the reporting period. For the years ended December 31, 2015 and 2014, there were no transfers between levels.

The fair value measurement of the retirement plan assets as of December 31, 2015, was as follows:



	Fair Value Measurements at Reporting Date Using
	Quoted Prices in		Significant		Significant
	Active Markets for		Other Observable		Unobservable
(In thousands)	Identical Assets		Inputs		Inputs
	(Level 1)		(Level 2)		(Level 3)
Financial assets measured on a recurring basis:
Mutual funds — U.S. equity securities	$	23,427	$	—	$	—
Mutual funds — international equity securities	5,409		—		—
Mutual funds — fixed income securities	29,291		—		—
Total	$	58,127	$	—	$	—

The fair value measurement of the retirement plan assets as of December 31, 2014, was as follows:



	Fair Value Measurements at Reporting Date Using
	Quoted Prices in		Significant		Significant
	Active Markets for		Other Observable		Unobservable
(In thousands)	Identical Assets		Inputs		Inputs
	(Level 1)		(Level 2)		(Level 3)
Financial assets measured on a recurring basis:
Mutual funds — U.S. equity securities	$	23,770	$	—	$	—
Mutual funds — international equity securities	5,096		—		—
Mutual funds — fixed income securities	23,783		—		—
Guaranteed deposit fund	—		3,741		—
Total	$	52,649	$	3,741	$	—

The mutual funds consist primarily of publicly traded mutual funds and are recorded at fair value based on observable trades for identical securities in an active market. The guaranteed deposit fund was a group annuity contract and was valued at estimated fair value by discounting the related cash flows based on current yields of similar instruments with comparable durations that were quoted in active markets, which represented the net asset value as of December 31, 2014. As of December 31, 2014, there were no unfunded commitments for the guaranteed deposit fund and the investment allowed a daily redemption with a one day notice.

Other Postretirement Benefits

We provide certain postretirement health care, dental and life insurance benefits for eligible employees. We contributed $9.1 million, $6.3 million and $1.5 million to the postretirement benefit plan in 2015, 2014 and 2013, respectively. We expect to contribute up to $9.2 million to the plan in 2016.

The plan assets consisted of the following assets by category:



Asset Category	2015		2014
Fixed income securities	50.0	%	57.2	%
Equity securities	50.0	%	42.8	%
Total	100.0	%	100.0	%

Our measurement of the accumulated postretirement benefit obligation as of December 31, 2015 and 2014 does not reflect the potential receipt of any subsidies under the Medicare Prescription Drug, Improvement and Modernization Act of 2003.

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Net postretirement benefit plan cost for 2015, 2014 and 2013 was as follows by component:



(In thousands)	2015			2014			2013
Service cost	$	8,486		$	5,846		$	5,774
Interest cost	2,477			1,991			1,562
Expected return on plan assets	(1,852		)	(1,361		)	(1,415		)
Amortization of unrecognized loss	499			—			220
Net postretirement cost	$	9,610		$	6,476		$	6,141

The following table reconciles the obligations, assets and funded status of the plan as well as the amounts recognized as accrued postretirement liability in the consolidated statements of financial position as of December 31, 2015 and 2014:



(In thousands)	2015			2014
Change in Benefit Obligation:
Beginning accumulated postretirement obligation	$	(57,927	)	$	(42,706	)
Service cost	(8,486		)	(5,846		)
Interest cost	(2,477		)	(1,991		)
Actuarial net gain (loss)	10,265			(7,695		)
Benefits paid	662			311
Other	8			—
Ending accumulated postretirement obligation	$	(57,955	)	$	(57,927	)
Change in Plan Assets:
Beginning plan assets at fair value	$	32,397		$	24,004
Actual return on plan assets	155			2,107
Employer contributions	9,122			6,286
Employer provided retiree premiums	662			311
Benefits paid	(662		)	(311		)
Other	(6		)	—
Ending plan assets at fair value	$	41,668		$	32,397
Funded status, underfunded	$	(16,287	)	$	(25,530	)
Amounts recorded as:
Funded Status:
Accrued postretirement liabilities	$	(16,287	)	$	(25,530	)
Total	$	(16,287	)	$	(25,530	)
Unrecognized Amounts in Non-current Regulatory Assets:
Net actuarial loss	$	191		$	9,258
Total	$	191		$	9,258

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Actuarial assumptions used to determine the benefit obligation at December 31, 2015, 2014 and 2013 are as follows:



	2015	2014	2013
Discount rate	4.62%	4.20%	5.15%
Annual rate of salary increases	4.00%	4.00%	4.00%
Health care cost trend rate assumed for next year	7.15%	7.25%	7.50%
Rate to which the cost trend rate is assumed to decline	5.00%	5.00%	5.00%
Year that the rate reaches the ultimate trend rate	2022	2022	2022
Annual rate of increase in dental benefit costs	5.00%	5.00%	5.00%

Actuarial assumptions used to determine the benefit cost for the years ended December 31, 2015, 2014 and 2013 are as follows:



	2015	2014	2013
Discount rate	4.20%	5.15%	4.20%
Annual rate of salary increases	4.00%	4.00%	5.00%
Health care cost trend rate assumed for next year	7.25%	7.50%	8.00%
Rate to which the cost trend rate is assumed to decline	5.00%	5.00%	5.00%
Year that the rate reaches the ultimate trend rate	2022	2022	2017
Expected long-term rate of return on plan assets	5.20%	5.50%	7.00%

At December 31, 2015, the projected benefit payments for the postretirement benefit plan calculated using the same assumptions as those used to calculate the benefit obligations listed above are as follows:



(In thousands)
2016	$	636
2017	734
2018	967
2019	1,241
2020	1,603
2021 through 2025	13,245

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point increase or decrease in assumed health care cost trend rates would have the following effects on costs for 2015 and the postretirement benefit obligation at December 31, 2015:



	One-Percentage-		One-Percentage-
(In thousands)	Point Increase		Point Decrease
Effect on total of service and interest cost	$	3,288	$	(2,282	)
Effect on postretirement benefit obligation	13,452		(9,869		)

Investment Objectives and Fair Value Measurement

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

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

The fair value measurement of the other postretirement benefit plan assets as of December 31, 2015, was as follows:



	Fair Value Measurements at Reporting Date Using
	Quoted Prices in		Significant		Significant
	Active Markets for		Other Observable		Unobservable
(In thousands)	Identical Assets		Inputs		Inputs
	(Level 1)		(Level 2)		(Level 3)
Financial assets measured on a recurring basis:
Cash and cash equivalents	$	30	$	—	$	—
Mutual funds — U.S. equity securities	19,981		—		—
Mutual funds — international equity securities	863		—		—
Mutual funds — fixed income securities	20,794		—		—
Total	$	41,668	$	—	$	—

The fair value measurement of the other postretirement benefit plan assets as of December 31, 2014, was as follows:



	Fair Value Measurements at Reporting Date Using
	Quoted Prices in		Significant		Significant
	Active Markets for		Other Observable		Unobservable
(In thousands)	Identical Assets		Inputs		Inputs
	(Level 1)		(Level 2)		(Level 3)
Financial assets measured on a recurring basis:
Cash and cash equivalents	$	5,099	$	—	$	—
Mutual funds — U.S. equity securities	13,070		—		—
Mutual funds — international equity securities	785		—		—
Mutual funds — fixed income securities	12,790		—		—
Guaranteed deposit fund	—		653		—
Total	$	31,744	$	653	$	—

Our investments included in cash equivalents consist of money market mutual funds and common and collective trusts that are administered similar to money market funds recorded at cost plus accrued interest to approximate fair value. Our mutual fund investments consist primarily of publicly traded mutual funds and are recorded at fair value based on observable trades for identical securities in an active market. The guaranteed deposit fund was a group annuity contract and was valued at estimated fair value based on the underlying assets of the fund by discounting the related cash flows based on current yields of similar instruments with comparable durations, which represented the net asset value as of December 31, 2014. As of December 31, 2014, there were no unfunded commitments for the guaranteed deposit fund and the investment allowed a daily redemption with a one day notice.

Defined Contribution Plan

We also sponsor a defined contribution retirement savings plan. Participation in this plan is available to substantially all employees. We match employee contributions up to certain predefined limits based upon eligible

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compensation and the employee’s contribution rate. The cost of this plan was $4.6 million, $4.5 million and $4.5 million in 2015, 2014 and 2013, respectively.

12. FAIR VALUE MEASUREMENTS

Our assets and liabilities measured at fair value subject to the three-tier hierarchy at December 31, 2015, were as follows:



	Fair Value Measurements at Reporting Date Using
(In thousands)	Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs			Significant Unobservable Inputs
	(Level 1)		(Level 2)			(Level 3)
Financial assets measured on a recurring basis:
Cash and cash equivalents — cash equivalents	$	49	$	—		$	—
Mutual funds — fixed income securities	35,813		—			—
Mutual funds — equity securities	976		—			—
Interest rate swap derivative	—		112			—
Financial liabilities measured on a recurring basis:
Interest rate swap derivatives	—		(3,548		)	—
Total	$	36,838	$	(3,436	)	$	—

Our assets and liabilities measured at fair value subject to the three-tier hierarchy at December 31, 2014, were as follows:



	Fair Value Measurements at Reporting Date Using
(In thousands)	Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs			Significant Unobservable Inputs
	(Level 1)		(Level 2)			(Level 3)
Financial assets measured on a recurring basis:
Cash and cash equivalents — cash equivalents	$	5,452	$	—		$	—
Mutual funds — fixed income securities	26,715		—			—
Mutual funds — equity securities	667		—			—
Financial liabilities measured on a recurring basis:
Interest rate swap derivatives	—		(1,934		)	—
Total	$	32,834	$	(1,934	)	$	—

As of December 31, 2015 and 2014, we held certain assets and liabilities that are required to be measured at fair value on a recurring basis. The assets included in the table consist of investments recorded within cash and cash equivalents and other long-term assets, including investments held in a trust associated with our supplemental nonqualified, noncontributory, retirement benefit plans for selected management employees. Our cash and cash equivalents consist of money market funds that are recorded at cost plus accrued interest to approximate fair value. Our mutual funds consist of publicly traded mutual funds and are recorded at fair value based on observable trades for identical securities in an active market. Changes in the observed trading prices and liquidity of money market funds are monitored as additional support for determining fair value. Gain and losses are recorded in

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earnings for investments classified as trading securities and other comprehensive income for investments classified as available-for-sale.

The asset and liability related to derivatives consist of interest rate swaps as discussed in Note 8. The fair value of our interest rate swap derivatives is determined based on a discounted cash flow (“DCF”) method using LIBOR swap rates, which are observable at commonly quoted intervals.

We also held non-financial assets that are required to be measured at fair value on a non-recurring basis. These consist of goodwill and intangible assets. We did not record any impairment charges on long-lived assets and no other significant events occurred requiring non-financial assets and liabilities to be measured at fair value (subsequent to initial recognition) during the years ended December 31, 2015 and 2014.

Fair Value of Financial Assets and Liabilities

Fixed Rate Debt

Based on the borrowing rates obtained from third party lending institutions currently available for bank loans with similar terms and average maturities from active markets, the fair value of our consolidated long-term debt and debt maturing within one year, excluding revolving and term loan credit agreements and commercial paper, was $3,879.7 million and $3,985.6 million at December 31, 2015 and 2014, respectively. These fair values represent Level 2 under the three-tier hierarchy described above. The total book value of our consolidated long-term debt and debt maturing within one year, net of discount and excluding revolving and term loan credit agreements and commercial paper, was $3,680.4 million and $3,629.8 million at December 31, 2015 and 2014, respectively.

Revolving and Term Loan Credit Agreements

At December 31, 2015 and 2014, we had a consolidated total of $680.9 million and $473.8 million, respectively, outstanding under our revolving and term loan credit agreements, which are variable rate loans. The fair value of these loans approximates book value based on the borrowing rates currently available for variable rate loans obtained from third party lending institutions. These fair values represent Level 2 under the three-tier hierarchy described above.

Other Financial Instruments

The carrying value of other financial instruments included in current assets and current liabilities, including cash and cash equivalents, special deposits and commercial paper, approximates their fair value due to the short-term nature of these instruments.

13. STOCKHOLDERS' EQUITY

Common Stock

General — At December 31, 2015, ITC Holdings’ authorized capital stock consisted of:


•	300 million shares of common stock, without par value; and


•	10 million shares of preferred stock, without par value.

As of December 31, 2015, there were 152,699,077 shares of our common stock outstanding (some of which are restricted stock awards and performance shares), no shares of preferred stock outstanding and 838 holders of record of our common stock.

Stock Split — On February 6, 2014, the board of directors declared a three-for-one split of our common stock to be accomplished by means of a stock distribution on February 28, 2014 to shareholders of record on February 18, 2014. All unvested restricted stock awards and outstanding stock option awards were adjusted under the terms of the respective agreements for this three-for-one split. The share and per share data in this Form 10-K reflects the three-for-one stock split effective February 28, 2014, unless otherwise noted.

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 (the “2014 ASR Program”) with JP Morgan Chase (“JP Morgan”) for up to $150.0 million, with a minimum commitment of $130.0 million. Under the 2014 ASR Program, ITC Holdings advanced $150.0 million to JP Morgan

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in June 2014 and received an initial delivery of 2.9 million shares with a fair market value of $104.0 million, based on the closing market price of $35.80 per share 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. Additionally, ITC Holdings received a repayment of the unused advance of $20.0 million. ITC Holdings recorded the net $130.0 million payment as a reduction to common stock as of December 31, 2014.

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, which is part of the share repurchase program described above. 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. ITC Holdings recorded the $115.0 million payment as a reduction to common stock as of December 31, 2015.

Voting Rights — Each holder of ITC Holdings’ common stock, including holders of our common stock subject to restricted stock and performance share awards, is entitled to cast one vote for each share held of record on all matters submitted to a vote of shareholders, including the election of directors. Holders of ITC Holdings’ common stock have no cumulative voting rights.

Dividends — Holders of our common stock, including holders of common stock subject to restricted stock and performance share awards, are entitled to receive dividends or other distributions declared by the board of directors. However, performance shares earn and accumulate dividend equivalents, which are settled in the form of additional shares upon vesting of the related award. Dividend equivalents paid on performance shares that do not vest will be forfeited. The right of the board of directors to declare dividends is subject to the right of any holders of ITC Holdings’ preferred stock, to the extent that any preferred stock is authorized and issued, and the availability under the Michigan Business Corporation Act of sufficient funds to pay dividends. We have not issued any shares of preferred stock. 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’ assets consist primarily of the stock and membership interests in its subsidiaries, deferred tax assets and cash on hand. ITC Holdings’ only sources of cash to pay dividends to our stockholders 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, however, is legally distinct from ITC Holdings 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 any of our other subsidiaries to pay dividends and make other payments to ITC Holdings is subject to, among other things, the availability of funds, after considering the capital expenditure requirements, the terms of its indebtedness, applicable state laws and regulations of the FERC and the FPA.

The debt agreements to which we are a party impose restrictions on ITC Holdings and its subsidiaries’ respective abilities to pay dividends if an event of default has occurred under the relevant agreement, and thus, ITC Holdings’ ability to pay dividends on its common stock will depend upon, among other things, our level of indebtedness at the time of the proposed dividend and whether we are in compliance with the covenants under our revolving and term loan credit facilities and our other debt instruments. ITC Holdings’ future dividend policy will also depend on the requirements of any future financing agreements to which we may be a party and other factors considered relevant by ITC Holdings’ board of directors.

Pursuant to SEC requirements, Schedule I included in Part IV Item 15 is required due to restrictions that limit the payment of dividends to ITC Holdings by its subsidiaries. Each of our Regulated Operating Subsidiaries as of December 31, 2015 are limited in using net assets for dividends based on management's intent to maintain the FERC-approved capital structure targeting 60% equity and 40% debt for each of our Regulated Operating Subsidiaries. These net assets are included in Schedule I as the line-item “Investments in subsidiaries.”

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Management does not expect that maintaining this targeted capital structure will have an impact on our ability to pay dividends at the current level in the foreseeable future.

Liquidation Rights — If ITC Holdings is dissolved, the holders of our common stock will share ratably in the distribution of all assets that remain after we pay all of our liabilities and satisfy our obligations to the holders of any of ITC Holdings’ preferred stock, to the extent that any preferred stock is authorized and issued.

Preemptive and Other Rights — Holders of our common stock have no preemptive rights to purchase or subscribe for any of our stock or other securities of our company and there are no conversion rights or redemption or sinking fund provisions with respect to our common stock.

Repurchases — In 2015, 2014 and 2013, we repurchased 4,201,847, 3,673,226 and 163,320 shares of common stock for an aggregate of $137.1 million, $134.3 million and $4.9 million, respectively, which represented shares of common stock delivered to us by employees as payment of tax withholdings due upon the vesting of restricted stock and shares delivered under the ASR programs described above.

Accumulated Other Comprehensive Income

The following table provides the components of changes in AOCI for the years ended December 31, 2015, 2014 and 2013:



	Year Ended December 31,
(In thousands)	2015			2014			2013
Balance at the beginning of period	$	4,816		$	6,327		$	(18,048	)
Derivative instruments
Reclassification of net loss (gain) relating to interest rate cash flow hedges from AOCI to interest expense — net (net of tax of $342, $349 and $436 for the years ended December 31, 2015, 2014 and 2013, respectively)	501			445			(25		)
Reclassification of loss relating to interest rate cash flow hedges from AOCI to loss on extinguishment of debt (net of tax of $83 for the year ended December 31, 2014)	—			117			—
(Loss) gain on interest rate swaps relating to interest rate cash flow hedges (net of tax of $625, $1,465 and $15,652 for the years ended December 31, 2015, 2014 and 2013, respectively)	(876		)	(2,041		)	24,329
Derivative instruments, net of tax	(375		)	(1,479		)	24,304
Available-for-sale securities
Unrealized (loss) gain on available-for-sale securities (net of tax of $126, $18 and $46 for the years ended December 31, 2015, 2014 and 2013, respectively)	(176		)	(32		)	71
Available-for-sale securities, net of tax	(176		)	(32		)	71
Total other comprehensive (loss) income, net of tax	(551		)	(1,511		)	24,375
Balance at the end of period	$	4,265		$	4,816		$	6,327

The amount of net loss relating to interest rate cash flow hedges to be reclassified from AOCI to interest expense for the 12-month period ending December 31, 2016 is not expected to be material.

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14. SHARE-BASED COMPENSATION

The share and per share data below reflects the three-for-one stock split effective February 28, 2014. See Note 13 for discussion on the stock split. Our 2015 LTIP, which was adopted by our board and approved by shareholders in 2015, permits the compensation committee to make grants of a variety of share-based awards (such as options, restricted stock, restricted stock units and performance shares) for a cumulative amount of up to 6,500,000 shares to employees, directors and consultants. The 2015 LTIP provides that no more than 4,600,000 of the shares may be granted as awards to be settled in shares of common stock other than options or stock appreciation rights. Under the 2015 LTIP agreement, no awards would be permitted after March 26, 2025. Prior to the adoption of the 2015 LTIP, we made various share-based awards under the 2006 LTIP, including options, restricted stock, deferred stock units and performance shares. In addition, our board of directors and shareholders approved a new ESPP in 2015, which replaced the previous ESPP, and allows for the issuance of an aggregate of 1,000,000 shares of our common stock. Participation in this plan is available to substantially all employees. ITC Holdings issues new shares to satisfy option exercises, restricted stock and performance share grants, employee ESPP purchases and settlement of deferred stock units. As of December 31, 2015, 11,276,238 shares were available for future issuance under our 2006 LTIP, 2015 LTIP and ESPP, including 3,817,200 shares issuable upon the exercise of outstanding stock options, of which 2,718,865 were vested.

We recorded share-based compensation in 2015, 2014 and 2013 as follows:



(In thousands)	2015		2014		2013
Operation and maintenance expenses	$	1,672	$	1,444	$	1,617
General and administrative expenses	10,546		8,549		9,318
Amounts capitalized to property, plant and equipment	5,391		4,659		4,731
Total share-based compensation	$	17,609	$	14,652	$	15,666
Total tax benefit recognized in the consolidated statement of operations	$	5,087	$	4,182	$	4,557

Tax deductions that exceed the cumulative compensation cost recognized for options exercised, restricted shares that vested or deferred stock units that are settled are recognized as common stock only if the tax deductions reduce taxes payable as a result of a realized cash benefit from the deduction. For the years ended December 31, 2015, 2014 and 2013, we recognized the tax effects of the excess tax deductions as an increase in common stock of $11.7 million, $7.8 million and $4.3 million, respectively, as the deductions have resulted in a reduction of taxes payable.

Options

Our option grants vest in equal annual installments over a 3 year period from the date of grant, or as a result of other events such as death or disability of the option holder. The options have a term of 10 years from the grant date.

Stock option activity for 2015 was as follows:



			Weighted
	Number of		Average
	Options		Exercise Price
Outstanding at January 1, 2015 (3,198,528 exercisable with a weighted average exercise price of $15.98)	4,603,292		$	20.71
Granted	473,200		35.91
Exercised	(1,203,376	)	9.44
Forfeited	(55,916	)	34.65
Outstanding at December 31, 2015 (2,718,865 exercisable with a weighted average exercise price of $22.38)	3,817,200		$	25.94

Grant date fair value of the stock options awards granted during 2015, 2014 and 2013 was determined using a Black-Scholes option pricing model. The following assumptions were used in determining the weighted average fair value per option:

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	2015			2014			2013
	Option Grants			Option Grants			Option Grants
Weighted average grant date fair value per option	$	6.05		$	8.92		$	7.06
Weighted average expected volatility (a)	18.6		%	27.2		%	29.3		%
Weighted average risk-free interest rate	1.8		%	1.8		%	1.1		%
Weighted average expected term (b)	6 years			6 years			6 years
Weighted average expected dividend yield	1.59		%	1.55		%	1.72		%
Estimated fair value of underlying shares	$	35.91		$	36.73		$	29.31

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(a)	We estimated volatility using the historical volatility of our stock.

(b)

The expected term represents the period of time that options granted are expected to be outstanding. We have utilized the simplified method permitted under share-based award accounting standards in determining the expected term for all option grants as we do not have sufficient historical exercise data to provide a reasonable basis upon which to estimate expected term due to the limited number of awards of equity shares that have reached expiration.

At December 31, 2015, the aggregate intrinsic value and the weighted average remaining contractual term for all outstanding options were approximately $50.8 million and 6.2 years, respectively. At December 31, 2015, the aggregate intrinsic value and the weighted average remaining contractual term for exercisable options were $45.9 million and 5.2 years, respectively. The aggregate intrinsic value of options exercised during 2015, 2014 and 2013 was $28.1 million, $18.5 million and $53.2 million, respectively. At December 31, 2015, the total unrecognized compensation cost related to the unvested options awards was $4.2 million and the weighted average period over which it is expected to be recognized was 1.6 years.

We estimate that 3,741,114 of the options outstanding at December 31, 2015 will vest, including those already vested. The weighted average exercise price, aggregate intrinsic value and the weighted average remaining contractual term for options shares that are vested and expected to vest as of December 31, 2015 was $25.76 per share, $50.5 million and 6.2 years, respectively.

Restricted Stock Awards

Holders of restricted stock awards have all the rights of a holder of common stock of ITC Holdings, including dividend and voting rights. The holder becomes vested as a result of certain events such as death or disability of the holder, but not later than the vesting date of the awards. Holders of restricted shares may not sell, transfer or pledge their restricted shares until the shares vest and the restrictions lapse. Restricted stock awards are recorded at fair value at the date of grant, which is based on the closing share price on the grant date. Awards that were granted for future services are treated as unearned compensation, with amounts amortized over the vesting period.

Restricted stock award activity for 2015 was as follows:



	Number of		Weighted
	Restricted		Average
	Stock		Grant Date
	Awards		Fair Value
Unvested restricted stock awards at January 1, 2015	1,223,819		$	28.37
Granted	259,039		36.30
Vested	(400,239	)	23.63
Forfeited	(58,209	)	26.65
Unvested restricted stock awards at December 31, 2015	1,024,410		$	32.10

The weighted average grant date fair value of restricted stock awarded during 2014 and 2013 was $36.75 and $29.42 per share, respectively. The aggregate fair value of restricted stock awards as of December 31, 2015 was $40.2 million. The aggregate fair value of restricted stock awards that vested during 2015, 2014 and 2013 was $14.5 million, $14.4 million and $15.8 million, respectively. At December 31, 2015, the total unrecognized compensation cost related to the restricted stock awards was $16.3 million and the weighted average period over which that cost is expected to be recognized was 2.2 years.

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As of December 31, 2015, we estimate that 907,864 shares of the restricted shares outstanding at December 31, 2015 will vest. The weighted average fair value, aggregate intrinsic value and the weighted average remaining contractual term for restricted shares that are expected to vest is $31.83 per share, $35.6 million and 1.4 years, respectively.

Performance Share Awards

Holders of performance share awards have all the rights of a holder of common stock of ITC Holdings, including dividend and voting rights. However, performance shares earn and accumulate dividend equivalents, which are settled in the form of additional shares upon vesting of the related award. Dividend equivalents paid on performance shares that do not vest will be forfeited. The performance share awards generally vest three years after the grant date, or as a result of certain events such as death or disability of the performance share award holder. Holders of performance shares may not sell, transfer or pledge their shares until the shares vest.

Approximately one-half of the performance share awards will be earned based on an external measure for total shareholder return (“TSR”) relative to a predetermined peer group (“TSR condition”) and the remainder will be earned based on adjusted diluted EPS growth (“EPS condition”). Payout of the performance share awards will range from 0% to 200% of the target number of shares granted, plus additional dividend equivalent shares on the earned portion of the performance share awards. The performance share awards with the EPS condition are recorded at fair value based on the closing price of ITC Holdings’ common stock on the grant date.

We recognize the fair value of the performance share awards on a straight-line basis (net of any estimated forfeitures) over the requisite service period of the awards. However, the compensation cost for the portion of the performance share awards subject to the EPS condition is recognized based on the probable payout (net of any estimated forfeitures), which is reassessed each reporting period and subject to change.



	Number of		Weighted
	Performance		Average
	Share		Grant Date
	Awards		Fair Value
Unvested performance share awards at January 1, 2015	—		$	—
Granted	287,464		32.55
Vested	—		—
Forfeited	(7,754	)	32.55
Unvested performance share awards at December 31, 2015	279,710		$	32.55

Grant date fair value of the portion of the performance share awards subject to the TSR condition granted during 2015 was determined using a Monte Carlo simulation valuation model. The following assumptions were used in determining the weighted average fair value per performance share with the TSR condition:



	2015
	Performance
	Share Grants
Weighted average grant date fair value per performance share	$	29.19
Weighted average expected volatility (a)	17.7		%
Weighted average risk-free interest rate	0.87		%
Estimated fair value of underlying shares	$	35.91

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(a)	We estimated volatility using the historical volatility of our stock.

The aggregate fair value of performance share awards as of December 31, 2015 was $11.0 million. At December 31, 2015, the total unrecognized compensation cost related to the performance share awards was $9.2 million and the weighted average period over which that cost is expected to be recognized was 2.4 years.

As of December 31, 2015, we estimate that 229,994 shares of the performance shares outstanding at December 31, 2015 will vest. The weighted average fair value, aggregate intrinsic value and the weighted average

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remaining contractual term for performance shares that are expected to vest is $32.55 per share, $9.0 million and 2.4 years, respectively.

Employee Stock Purchase Plan

The ESPP is a compensatory plan accounted for under the expense recognition provisions of the share-based payment accounting standards. Compensation cost is recorded based on the fair market value of the purchase options at the grant date, which corresponds to the first day of each purchase period and is amortized over the purchase period. During 2015, 2014 and 2013, employees purchased 76,041, 69,230 and 77,097 shares, respectively, resulting in proceeds from the sale of our common stock of $2.3 million, $2.1 million and $1.9 million, respectively, under the ESPP. The total share-based compensation amortization for the ESPP was $0.5 million, $0.5 million and $0.4 million for the years ended December 31, 2015, 2014 and 2013, respectively.

15. JOINTLY OWNED UTILITY PLANT/COORDINATED SERVICES

Our Regulated Operating Subsidiaries have agreements with other utilities for the joint ownership of substation assets and transmission lines. We account for these jointly owned assets by recording property, plant and equipment for our percentage of ownership interest. Various agreements provide the authority for construction of capital improvements and the operating costs associated with the substations and lines. Generally, each party is responsible for the capital, operation and maintenance and other costs of these jointly owned facilities based upon each participant’s undivided ownership interest. Our Regulated Operating Subsidiaries’ participating share of expenses associated with these jointly held assets are primarily recorded within operation and maintenance expenses on our consolidated statement of operations.

We have investments in jointly owned utility assets as shown in the table below as of December 31, 2015:



	Net		Construction
(In thousands)	Investments (a)		Work in Progress
Substations	$	31,640	$	4,455
Lines	102,703		2,718
Total	$	134,343	$	7,173

____________________________


(a)	Amount represents our investment in jointly held plant, which has been reduced by the ownership interest amounts of other parties.

ITCTransmission

ITCTransmission has joint ownership in two 345 kV transmission lines with a municipal power agency that has a 50.4% ownership interest in the transmission lines. ITCTransmission’s net investment in these two lines totaled $28.8 million as of December 31, 2015. The municipal power agency’s ownership portion entitles them to approximately 234 MW of network transmission service from the ITCTransmission system. An Ownership and Operating Agreement with the municipal power agency provides ITCTransmission with authority for construction of capital improvements and for the operation and management of the transmission lines. The municipal power agency is responsible for the capital and operation and maintenance costs allocable to their ownership interest.

METC

METC has joint sharing of several assets within various substations with Consumers Energy, other municipal distribution systems and other generators. The rights, responsibilities and obligations for these jointly owned assets are documented in the Amended and Restated Distribution — Transmission Interconnection Agreement with Consumers Energy and in numerous interconnection facilities agreements with various municipalities and other generators. As of December 31, 2015, METC had net investments in jointly owned substation facilities totaling $13.9 million (including less than $0.1 million of jointly owned substation assets under construction) of which METC’s ownership percentages for these jointly owned substation assets ranged from 6.3% to 92.0%. In addition, other municipal power agencies and cooperatives have an ownership interest in several METC 345 kV transmission lines. This ownership entitles these municipal power agencies and cooperatives to approximately 608 MW of network transmission service from the METC transmission system. As of December 31, 2015, METC had net investments in jointly shared transmission lines totaling $41.0 million of which METC’s ownership percentages for these jointly owned lines ranged from 1.0% to 41.9%.

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ITC Midwest

ITC Midwest has joint sharing of several substations and transmission lines with various parties. As of December 31, 2015, ITC Midwest had net investments in jointly shared substation facilities totaling $18.4 million (including $0.7 million of jointly owned substation assets under construction) of which ITC Midwest’s ownership percentages for these jointly owned substations facilities ranged from 28.0% to 80.0%. As of December 31, 2015, ITC Midwest had net investments in jointly shared transmission lines totaling $32.9 million (including less than $0.1 million of jointly owned lines under construction) of which ITC Midwest’s ownership percentage for these jointly owned lines ranged from 48.0% to 80.0%.

ITC Great Plains

In May 2014, ITC Great Plains entered into a joint ownership agreement with an electric cooperative that has a 49.0% ownership interest in the transmission project. ITC Great Plains will construct and operate the project and the electric cooperative will be responsible for their ownership percentage of capital and operation and maintenance costs. As of December 31, 2015, ITC Great Plains had net investment in the project that is currently under construction of $6.5 million of which ITC Great Plains’ ownership percentage was 51.0%.

16. COMMITMENTS AND CONTINGENT LIABILITIES

Environmental Matters

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

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electric transmission and distribution lines that entail costs likely to have a material adverse effect on our results of operations, financial position or liquidity.

Litigation

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

Michigan Sales and Use Tax Audit

The Michigan Department of Treasury has conducted sales and use tax audits of ITCTransmission for the audit periods April 1, 2005 through June 30, 2008 and October 1, 2009 through September 30, 2013. The Michigan Department of Treasury has denied ITCTransmission’s claims of the industrial processing exemption from use tax that it has taken beginning January 1, 2007. The exemption claim denials resulted in use tax assessments against ITCTransmission. ITCTransmission filed administrative appeals to contest these use tax assessments.

In a separate, but related case involving a Michigan-based public utility that made similar industrial processing exemption claims, the Michigan Supreme Court ruled in July 2015 that the electric system, which involves altering voltage, constitutes an exempt, industrial processing activity. However, the ruling further held the electric system is also used for other functions that would not be exempt, and remanded the case to the Michigan Court of Claims to determine how the exemption applies to assets that are used in electric distribution activities. ITCTransmission is assessing the recent ruling in light of its specific facts, but cannot estimate the timing of any potential tax assessments or refunds.

The amount of use tax associated with the exemptions taken by ITCTransmission through December 31, 2015 is estimated to be approximately $18.0 million, including interest. This amount includes approximately $10.4 million, including interest, assessed for the audit periods noted above. ITCTransmission believes it is probable that portions of the use tax assessments could be sustained upon resolution of this matter. ITCTransmission has recorded $5.9 million for this contingent liability, including interest, as of December 31, 2015, primarily as an increase to property, plant and equipment, which is a component of revenue requirement in our cost-based formula rate.

METC has also taken the industrial processing exemption, estimated to be approximately $10.5 million for periods still subject to audit. METC has not been assessed any use tax liability and has not recorded any contingent liability as of December 31, 2015 associated with this matter. In the event it becomes appropriate to record additional use tax liability relating to this matter, ITCTransmission and METC would record the additional use tax primarily as an increase to the cost of property, plant and equipment, as the majority of purchases for which the exemption was taken relate to equipment purchases associated with capital projects.

Rate of Return on Equity and Capital Structure Complaints

On November 12, 2013, the Association of Businesses Advocating Tariff Equity, Coalition of MISO Transmission Customers, Illinois Industrial Energy Consumers, Indiana Industrial Energy Consumers, Inc., Minnesota Large Industrial Group and Wisconsin Industrial Energy Group (collectively, the “complainants”) filed a complaint with the FERC under Section 206 of the FPA (the “Initial Complaint”), requesting that the FERC find the 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%. The Initial Complaint also alleged that the rates of any MISO TO using a capital structure with greater than 50% for the equity component are likewise not just and reasonable (our MISO Regulated Operating Subsidiaries use their actual capital structures, which target 60% equity, as FERC had previously authorized). The Initial Complaint also alleged the ROE adders currently approved for certain ITC Holdings operating companies, including an adder currently charged by ITCTransmission for being a member of an RTO and adders charged by ITCTransmission and METC for being independent TOs, are no longer just and reasonable, and sought to have them eliminated.

On June 19, 2014, in a separate Section 206 complaint against the regional base ROE rate for ISO New England TOs, FERC adopted a new methodology for establishing base ROE rates for electric transmission utilities. The new methodology is based on a two-step DCF analysis (“two-step DCF”) that uses both short-term and long-term

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growth projections in calculating ROE rates for a proxy group of electric utilities. The previous methodology used only short-term growth projections. FERC also reiterated that it can apply discretion in determining how ROE rates are established within a zone of reasonableness and reiterated its policy for limiting the overall ROE rate for any company, including the base and all applicable adders, at the high end of the zone of reasonableness set by the two-step DCF methodology. The new method presented in the ISO New England ROE case will be used in resolving the MISO ROE case.

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 for 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 Arkansas Electric Cooperative Corporation, Mississippi Delta Energy Agency, Clarksdale Public Utilities Commission, Public Service Commission of Yazoo City and Hoosier Energy Rural Electric Cooperative, Inc., seeking a FERC order to reduce the base ROE used in 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.

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of $73.2 million for the year ended December 31, 2015 (which includes a $28.4 million effect on net income for revenue initially recognized in 2014 and 2013) and $28.9 million for the year ended December 31, 2014 (which includes a $2.9 million effect on net income for revenue initially recognized in 2013). No amounts related to these complaints were recorded as of or for the year ended December 31, 2013.

Purchase Obligations and Leases

At December 31, 2015, we had purchase obligations of $61.4 million representing commitments 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 purchase obligations are expected to be paid in 2016, with the majority of the items related to materials and equipment that have long production lead times.

We have operating leases for office space, equipment and storage facilities. We recognize expenses relating to our operating lease obligations on a straight-line basis over the term of the lease. We recognized rent expense of $1.1 million, $1.0 million and $0.8 million for the years ended December 31, 2015, 2014 and 2013, respectively, recorded in general and administrative expenses as well as operation and maintenance expenses. These amounts and the amounts in the table below do not include any expense or payments to be made under the METC Easement Agreement described below under “Other Commitments — METC — Amended and Restated Easement Agreement with Consumers Energy.”

Future minimum lease payments under the leases at December 31, 2015 were:



(In thousands)
2016	$	932
2017	824
2018	700
2019	545
2020 and thereafter	1,971
Total minimum lease payments	$	4,972

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Other Commitments

METC

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

Amended and Restated Easement Agreement with Consumers Energy. The Easement Agreement with Consumers Energy (the “Easement Agreement”) provides METC with an easement for transmission purposes and rights-of-way, leasehold interests, fee interests and licenses associated with the land over which the transmission lines cross. Consumers Energy has reserved for itself the rights to other uses of the infrastructure (such as for fiber optics, telecommunications and gas pipelines), along with the value of activities associated with such uses. The cost for use of the rights-of-way is $10.0 million per year. The term of the Easement Agreement runs through December 31, 2050 and is subject to 10 automatic 50-year renewals thereafter. Payments to Consumers Energy under the Easement Agreement are charged to operation and maintenance expenses.

ITC Midwest

Operations Services Agreement For 34.5 kV Transmission Facilities. ITC Midwest and IP&L have entered into the Operations Services Agreement For 34.5 kV Transmission Facilities (the “OSA”), effective as of January 1, 2011, under which IP&L performs certain operations of ITC Midwest’s 34.5 kV transmission system. The OSA will remain in full force and effect until December 31, 2015 and will extend automatically from year to year thereafter until terminated by either party upon not less than one year prior written notice to the other party.

ITC Great Plains

Amended and Restated Maintenance Agreement. Mid-Kansas Electric Company LLC (“Mid-Kansas”) and ITC Great Plains have entered into a Maintenance Agreement (the “Mid-Kansas Agreement”), dated as of August 24, 2010, and most recently amended effective as of June 1, 2015, pursuant to which Mid-Kansas has agreed to perform various field operations and maintenance services related to certain ITC Great Plains assets. The Mid-Kansas Agreement has an initial term of 10 years and automatic 10-year renewal terms unless terminated (1) due to a breach by the non-terminating party following notice and failure to cure, (2) by mutual consent of the parties, or (3) by ITC Great Plains under certain limited circumstances. Services must continue to be provided for at least six months subsequent to the termination date in any case.

Concentration of Credit Risk

Our credit risk is primarily with DTE Electric, Consumers Energy and IP&L, which were responsible for approximately 20.8%, 21.9% and 26.8%, respectively, or $232.6 million, $244.6 million and $299.9 million, respectively, of our consolidated billed revenues for the year ended December 31, 2015. These percentages and amounts 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 financial difficulties experienced by DTE Electric, Consumers Energy or IP&L could negatively impact our business. MISO, as our MISO Regulated Operating Subsidiaries’ billing agent, bills DTE Electric, Consumers Energy, IP&L and other customers on a monthly basis and collects fees for the use of our transmission systems. SPP bills customers of ITC Great Plains on a monthly basis and collects fees for the use of ITC Great Plains’ assets. MISO and SPP have implemented strict credit policies for its members’ customers, which include customers using our transmission

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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.

17. ENTERGY TRANSACTION

In 2011, Entergy and ITC Holdings executed definitive agreements under which Entergy would divest and then merge its electric transmission business with a wholly-owned subsidiary of ITC Holdings. Completion of the transaction was subject to the satisfaction of certain closing conditions, including the receipt of necessary approvals of Entergy’s retail regulators. On December 10, 2013, the Mississippi Public Service Commission issued an order denying permission to transfer ownership and control of Entergy Mississippi Inc.’s transmission assets to a subsidiary of ITC Holdings. On December 13, 2013, ITC Holdings and Entergy mutually agreed to terminate the Entergy Transaction.

For the years ended December 31, 2014 and 2013, we expensed external legal, advisory and financial services fees related to the terminated Entergy Transaction of $0.4 million and $43.1 million, respectively, and certain internal labor and associated costs related to the terminated Entergy Transaction of $0.7 million and $7.8 million, respectively. Due to the cancellation of the Entergy Transaction, we recognized tax benefits of $5.6 million during the fourth quarter of 2013 for expenses that were previously deemed non-deductible for tax purposes. The external and internal costs related to the Entergy Transaction were not included as components of revenue requirement at our Regulated Operating Subsidiaries as they were incurred at ITC Holdings.

18. SEGMENT INFORMATION

We identify reportable segments based on the criteria set forth by the FASB regarding disclosures about segments of an enterprise, including the regulatory environment of our subsidiaries and the business activities performed to earn revenues and incur expenses.

Regulated Operating Subsidiaries

We aggregate ITCTransmission, METC, ITC Midwest and ITC Great Plains into one reportable operating segment based on their similar regulatory environment and economic characteristics, among other factors. They are engaged in the transmission of electricity within the United States, earn revenues from the same types of customers and are regulated by the FERC. Their tariff rates are established using cost-based formula rates.

ITC Holdings and Other

Information below for ITC Holdings and Other consists of a holding company whose activities include debt and equity financings and general corporate activities and all of ITC Holdings’ other subsidiaries, excluding the Regulated Operating Subsidiaries, which are focused primarily on business development activities.



	Regulated
	Operating		ITC Holdings			Reconciliations/
2015	Subsidiaries		and Other			Eliminations			Total
(In thousands)
Operating revenues	$	1,044,311	$	1,057		$	(600	)	$	1,044,768
Depreciation and amortization	143,956		716			—			144,672
Interest expense — net	97,337		106,442			—			203,779
Income (loss) before income taxes	529,484		(145,607		)	—			383,877
Income tax provision (benefit)	200,582		(59,111		)	—			141,471
Net income	328,902		242,406			(328,902		)	242,406
Property, plant and equipment — net	6,093,499		16,140			—			6,109,639
Goodwill	950,163		—			—			950,163
Total assets (a)	7,479,286		4,158,986			(4,056,150		)	7,582,122
Capital expenditures	687,988		3,428			(7,276		)	684,140

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	Regulated
	Operating		ITC Holdings			Reconciliations/
2014	Subsidiaries		and Other			Eliminations			Total
(In thousands)
Operating revenues	$	1,023,170	$	605		$	(727	)	$	1,023,048
Depreciation and amortization	127,320		716			—			128,036
Interest expense — net	81,225		105,418			(7		)	186,636
Income (loss) before income taxes	548,704		(154,299		)	—			394,405
Income tax provision (benefit)	210,914		(60,592		)	—			150,322
Net income	337,790		244,083			(337,790		)	244,083
Property, plant and equipment — net	5,483,093		13,782			—			5,496,875
Goodwill	950,163		—			—			950,163
Total assets (a) (b)	6,854,387		3,944,318			(3,839,127		)	6,959,578
Capital expenditures	736,751		1,471			(5,077		)	733,145



	Regulated
	Operating		ITC Holdings			Reconciliations/
2013	Subsidiaries		and Other			Eliminations			Total
(In thousands)
Operating revenues	$	941,571	$	567		$	(866	)	$	941,272
Depreciation and amortization	117,924		672			—			118,596
Interest expense — net	70,239		98,660			(580		)	168,319
Income (loss) before income taxes	515,327		(162,959		)	—			352,368
Income tax provision (benefit)	193,764		(74,902		)	—			118,862
Net income	321,563		233,506			(321,563		)	233,506
Property, plant and equipment — net	4,833,545		12,981			—			4,846,526
Goodwill	950,163		—			—			950,163
Total assets (a) (b)	6,159,153		3,619,759			(3,513,894		)	6,265,018
Capital expenditures	824,165		2,208			(4,785		)	821,588

____________________________


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


(b)	Amounts reflect the change in the authoritative guidance on the presentation of deferred income taxes on the balance sheet. Refer to Notes 3 and 10 for more information.

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19. SUPPLEMENTARY QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Quarterly earnings per share amounts may not sum to the totals for each of the years, since quarterly computation are based on weighted average common shares outstanding during each quarter.



	First		Second		Third		Fourth
(In thousands, except per share data)	Quarter		Quarter		Quarter		Quarter		Year
2015
Operating revenues (a)(b)	$	272,487	$	275,058	$	273,189	$	224,034	$	1,044,768
Operating income (a)(b)	149,452		158,408		149,644		103,213		560,717
Net income (a)(b)	67,132		72,336		65,573		37,365		242,406
Basic earnings per share	$	0.43	$	0.47	$	0.42	$	0.25	$	1.57
Diluted earnings per share	$	0.43	$	0.46	$	0.42	$	0.24	$	1.56
2014
Operating revenues (a)	$	258,603	$	263,214	$	270,134	$	231,097	$	1,023,048
Operating income (a)	153,441		158,928		161,432		119,028		592,829
Net income (a)(c)	69,136		54,336		73,873		46,738		244,083
Basic earnings per share	$	0.44	$	0.34	$	0.47	$	0.30	$	1.56
Diluted earnings per share	$	0.43	$	0.34	$	0.47	$	0.30	$	1.54

____________________________

(a)

During the year ended December 31, 2015 and the fourth quarter of 2014, we recognized an aggregate estimated regulatory liability for the potential refunds relating to the ROE complaints as described in Note 16, which resulted in a reduction in operating revenues and operating income of $115.1 million and $46.9 million and an estimated $73.2 million and $28.9 million reduction to net income for the years ended December 31, 2015 and 2014, respectively.


(b)	During the third and fourth quarters of 2015, we recognized an aggregate regulatory liability for the refund relating to the formula rate template modifications filing as described in Note 4, which resulted in a reduction in operating revenues and operating income of $9.5 million and an estimated $6.2 million reduction to net income for the year ended December 31, 2015.


(c)	During the second quarter of 2014, we incurred a loss on extinguishment of debt of $29.2 million related to the tender of ITC Holdings Senior Notes as described in Note 8, which resulted in an estimated reduction to net income of $18.2 million.

20. SUBSEQUENT EVENTS

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. Upon completion of the Merger, ITC Holdings shareholders will hold approximately 27% of the common shares of Fortis. Fortis will apply to list its common shares on the New York Stock Exchange and will continue to have its shares listed on the Toronto Stock Exchange.

The closing of the Merger, expected to occur in late 2016, is subject to approval by ITC Holdings’ shareholders and the shareholders of Fortis, the satisfaction of other customary closing conditions and certain regulatory, state and federal approvals including, among others, those of the FERC, the Committee on Foreign Investment in the U.S., the U.S. Federal Trade Commission, the U.S. Department of Justice and various state utilities regulators. Many of these conditions are outside our control, and we cannot provide any assurance as to whether or when the Merger will be consummated or whether our shareholders will realize the anticipated benefits of completing the Merger. Also, if the Merger does not receive timely regulatory approval or if an event occurs that delays or prevents the Merger, such delay or failure to complete the Merger may cause uncertainty and other negative consequences that may materially and adversely affect our business, financial position and results of operations.

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The Merger Agreement contains certain termination rights, including the right of ITC Holdings to terminate the Merger Agreement to accept a superior proposal (subject to compliance with certain notice and other requirements). In addition, subject to certain exceptions and limitations, ITC Holdings or Fortis may terminate the Merger Agreement if the Merger is not consummated by February 9, 2017 (as such date may be extended pursuant to the terms of the Merger Agreement). The Merger Agreement provides that, in connection with termination of the Merger Agreement by ITC Holdings or Fortis upon specified conditions, a termination fee of $245 million may be required to be paid by ITC Holdings or Fortis. If the Merger Agreement is terminated as a result of the failure to obtain certain regulatory approvals or due to a legal prohibition related to regulatory matters, a termination fee of $280 million will be payable by Fortis to ITC Holdings, subject to certain limitations.

In 2016, through the date of this filing, we have incurred an estimated amount of external legal, advisory and financial services fees and certain internal labor and associated costs related to the Merger of approximately $10 million. Amounts expensed during the year ended December 31, 2015 related to the Merger were not material. The external and internal costs related to the Merger will not be included as components of revenue requirement at our Regulated Operating Subsidiaries as they were incurred at ITC Holdings.

Per the Merger Agreement, prior to completion of the Merger, there are certain restrictions on our ability to pay dividends other than those paid in the ordinary course of business with record dates and payment dates consistent with our past practice. Management does not expect the restrictions to have an impact on our ability to pay dividends at the current level for the foreseeable future.


ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.

None.

ITEM 9A. CONTROLS AND PROCEDURES.

Management’s Report on Internal Control Over Financial Reporting is included in Item 8 of this Form 10-K. The attestation report of Deloitte & Touche LLP, our independent registered public accounting firm, on the effectiveness of our internal control over financial reporting is also included in Item 8 of this Form 10-K.

Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to provide reasonable assurance that material information required to be disclosed in our reports that we file or submit under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required financial disclosure. In designing and evaluating the disclosure controls and procedures, management recognized that a control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, with a company have been detected.

As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 of the Exchange Act. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective, at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

There have been no changes in our internal control over financial reporting during the quarter ended December 31, 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION.

None.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.

The information required by this Item is contained under the captions “Election of Directors,” “Executive Officers,” “Section 16(a) Beneficial Ownership Reporting Compliance” and “Corporate Governance” in the Proxy Statement and (excluding the report of the Audit Committee) is incorporated herein by reference.

ITEM 11. EXECUTIVE COMPENSATION.

The information required by this Item is contained under the caption “Compensation of Executive Officers and Directors” in the Proxy Statement and is incorporated herein by reference.


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

The information required by this Item is contained under the caption “Security Ownership of Management and Major Shareholders” in the Proxy Statement and is incorporated herein by reference.

Equity Compensation Plans

The Company makes equity-based grants to employees, directors and consultants under the 2015 LTIP, issues shares to employees under the ESPP, and previously made equity-based grants to employees and directors under the 2006 LTIP, all of which plans were previously approved by shareholders.

The following table sets forth certain information with respect to our equity compensation plans at December 31, 2015 (shares in thousands):



				Number of Shares
				Remaining Available
	Number of Shares			for Future Issuance
	to be Issued	Weighted Average		Under Equity
	Upon Exercise of	Exercise Price of		Compensation
Plan Category	Outstanding Options	Outstanding Options		Plans(a)
Equity compensation plans approved by shareholders	3,817	$	25.94	11,276

____________________________

(a)

The number of shares remaining available for future issuance under equity compensation plans has been reduced by: 1) the common shares issued through December 31, 2015 upon exercise of stock options; 2) the number of common shares that could be issued upon the future exercise of outstanding stock options; and 3) the number of outstanding shares underlying restricted stock and performance share awards granted that have not been forfeited. The 2015 LTIP imposes a separate restriction so that no more than 4,600,000 of the shares may be granted as awards to be settled in shares of common stock other than options or stock appreciation rights.

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

The information required by this Item is contained under the captions “Certain Transactions” and “Corporate Governance — Director Independence” in the Proxy Statement and is incorporated herein by reference.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.

The information required by this Item is contained under the caption “Proposal 3 — Approval of Independent Registered Public Accounting Firm — Independent Registered Public Accounting Firm” in the Proxy Statement and is incorporated herein by reference.

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.



(a)	(1)	Financial Statements:
		Management’s Report on Internal Control over Financial Reporting
		Report of Independent Registered Public Accounting Firm
		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
	(2)	Financial Statement Schedules
		Schedule I — Condensed Financial Information of Registrant
		All other schedules for which provision is made in Regulation S-X either (i) are not required under the related instructions or are inapplicable and, therefore, have been omitted, or (ii) the information required is included in the consolidated financial statements or the notes thereto that are a part hereof.
(b)		The exhibits included as part of this report are listed in the attached Exhibit Index, which is incorporated herein by reference. At the request of any shareholder, ITC Holdings will furnish any exhibit upon the payment of a fee of $.10 per page to cover the costs of furnishing the exhibit.

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SCHEDULE I — Condensed Financial Information of Registrant

ITC HOLDINGS CORP.

CONDENSED STATEMENTS OF FINANCIAL POSITION (PARENT COMPANY ONLY)



	December 31,
(In thousands, except share data)	2015		2014
ASSETS
Current assets
Cash and cash equivalents	$	8,185	$	6,305
Accounts receivable from subsidiaries	38,010		42,665
Prepaid and other current assets	1,674		1,655
Total current assets	47,869		50,625
Other assets
Investment in subsidiaries	4,010,767		3,784,609
Deferred income taxes	21,241		25,887
Deferred financing fees (net of accumulated amortization of $6,670 and $4,700, respectively)	12,322		14,117
Other	64,098		67,376
Total other assets	4,108,428		3,891,989
TOTAL ASSETS	$	4,156,297	$	3,942,614
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	3,421	$	2,431
Accrued payroll	24,123		23,502
Accrued interest	34,836		34,815
Debt maturing within one year	395,334		—
Other	7,084		4,266
Total current liabilities	464,798		65,014
Accrued pension and postretirement liabilities	61,609		69,562
Other	1,186		3,237
Long-term debt (net of discounts of $3,404 and $3,940, respectively)	1,919,633		2,135,244
STOCKHOLDERS’ EQUITY
Common stock, without par value, 300,000,000 shares authorized, 152,699,077 and 155,140,967 shares issued and outstanding at December 31, 2015 and 2014, respectively	829,211		923,191
Retained earnings	875,595		741,550
Accumulated other comprehensive income	4,265		4,816
Total stockholders’ equity	1,709,071		1,669,557
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	4,156,297	$	3,942,614

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

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SCHEDULE I — Condensed Financial Information of Registrant

ITC HOLDINGS CORP.

CONDENSED STATEMENTS OF OPERATIONS (PARENT COMPANY ONLY)



	Year Ended December 31,
(In thousands)	2015			2014			2013
Other income	$	996		$	786		$	1,487
General and administrative expense	(5,526		)	(7,336		)	(56,707		)
Interest expense	(106,442		)	(105,411		)	(98,660		)
Loss on extinguishment of debt	—			(29,205		)	—
Other expense	(163		)	(196		)	(3,609		)
LOSS BEFORE INCOME TAXES	(111,135		)	(141,362		)	(157,489		)
INCOME TAX BENEFIT	(45,652		)	(55,646		)	(72,798		)
LOSS AFTER TAXES	(65,483		)	(85,716		)	(84,691		)
EQUITY IN SUBSIDIARIES’ NET EARNINGS	307,889			329,799			318,197
NET INCOME	$	242,406		$	244,083		$	233,506

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

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SCHEDULE I — Condensed Financial Information of Registrant

ITC HOLDINGS CORP.

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (PARENT COMPANY ONLY)



	Year Ended December 31,
(In thousands)	2015			2014			2013
NET INCOME	$	242,406		$	244,083		$	233,506
OTHER COMPREHENSIVE (LOSS) INCOME
Derivative instruments (net of tax of $967, $1,897 and $16,087 for the years ended December 31, 2015, 2014 and 2013, respectively)	(375		)	(1,479		)	24,304
Available-for-sale securities (net of tax of $126, $18 and $46 for the years ended December 31, 2015, 2014 and 2013, respectively)	(176		)	(32		)	71
TOTAL OTHER COMPREHENSIVE (LOSS) INCOME, NET OF TAX	(551		)	(1,511		)	24,375
TOTAL COMPREHENSIVE INCOME	$	241,855		$	242,572		$	257,881

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

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SCHEDULE I — Condensed Financial Information of Registrant

ITC HOLDINGS CORP.

CONDENSED STATEMENTS OF CASH FLOWS (PARENT COMPANY ONLY)



	Year Ended December 31,
(In 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:
Equity in subsidiaries' earnings	(307,889		)	(329,799		)	(318,197		)
Dividends from subsidiaries	185,303			224,167			169,973
Deferred and other income taxes	(116,243		)	(122,413		)	(117,956		)
Loss on extinguishment of debt	—			29,205			—
Intercompany tax payments from subsidiaries	120,863			124,315			112,008
Share-based compensation expense	17,674			14,652			15,667
Other	3,108			2,852			(226		)
Changes in assets and liabilities, exclusive of changes shown separately:
Accounts receivable from subsidiaries	3,158			1,304			(979		)
Prepaid and other current assets	92			4,154			16,948
Accounts payable	990			(3,869		)	(2,294		)
Accrued payroll	621			1,572			1,190
Accrued interest	21			(2,671		)	6,501
Accrued taxes	8,996			11,147			(179		)
Tax benefit on the excess tax deduction of share-based compensation	(11,707		)	(7,767		)	(4,302		)
Other current liabilities	2,416			(2,425		)	2,278
Other non-current assets and liabilities, net	6,006			3,078			12,465
Net cash provided by operating activities	155,815			191,585			126,403
CASH FLOWS FROM INVESTING ACTIVITIES
Equity contributions to subsidiaries	(263,150		)	(348,661		)	(339,770		)
Return of capital from subsidiaries	161,075			126,900			96,120
Proceeds from sale of marketable securities	673			495			20,844
Purchases of marketable securities	(10,422		)	(6,091		)	(22,250		)
Other	(750		)	(984		)	—
Net cash used in investing activities	(112,574		)	(228,341		)	(245,056		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	—			398,664			548,484
Borrowings under revolving credit agreement	838,900			533,900			222,800
Borrowings under term loan credit agreements	—			60,000			390,000
Net issuance of commercial paper, net of discount	94,630			—			—
Retirement of long-term debt - including extinguishment of debt costs	—			(248,625		)	(267,000		)
Repayments of revolving credit agreement	(754,700		)	(480,400		)	(252,400		)
Repayments of term loan credit agreements	—			(39,000		)	(450,000		)
Issuance of common stock	13,635			20,713			10,042
Dividends on common and restricted stock	(108,275		)	(95,595		)	(84,129		)
Repurchase and retirement of common stock	(137,081		)	(134,284		)	(4,885		)
Tax benefit on the excess tax deduction of share-based compensation	11,707			7,767			4,302
Advance for forward contract of accelerated share repurchase program	—			(20,000		)	—
Return of unused advance for forward contract of accelerated share repurchase program	—			20,000			—
Other	(177		)	(6,932		)	5,746
Net cash (used in) provided by financing activities	(41,361		)	16,208			122,960
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	1,880			(20,548		)	4,307
CASH AND CASH EQUIVALENTS — Beginning of period	6,305			26,853			22,546
CASH AND CASH EQUIVALENTS — End of period	$	8,185		$	6,305		$	26,853

Supplementary cash flows information:
Interest paid (net of interest capitalized)	$	103,915		$	105,817		$	90,224
Income taxes paid — net	55,722			44,524			20,092
Supplementary non-cash investing and financing activities:
Equity transfers to subsidiaries	1,497			6,227			6,213

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

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SCHEDULE I — Condensed Financial Information of Registrant

ITC HOLDINGS CORP.

NOTES TO CONDENSED FINANCIAL STATEMENTS (PARENT COMPANY ONLY)

1. GENERAL

For ITC Holdings Corp.’s (“ITC Holdings,” “we,” “our” and “us”) presentation (Parent Company only), the investment in subsidiaries is accounted for using the equity method. The condensed parent company financial statements and notes should be read in conjunction with the consolidated financial statements and notes of ITC Holdings appearing in this Annual Report on Form 10-K.

As a holding company with no business operations, ITC Holdings’ assets consist primarily of investments in our subsidiaries. ITC Holdings’ material cash inflows are only from dividends and other payments received from our subsidiaries, the proceeds raised from the sale of debt and equity securities, issuances under our commercial paper program and borrowings under our revolving credit agreement. ITC Holdings may not be able to access cash generated by our subsidiaries in order to fulfill cash commitments or pay dividends to shareholders. The ability of our subsidiaries to make dividend and other payments to us is subject to the availability of funds after taking into account their respective funding requirements, the terms of their respective indebtedness, the regulations of the FERC under the FPA and applicable state laws. In addition, there are practical limitations on using the net assets of each of our Regulated Operating Subsidiaries as of December 31, 2015 for dividends based on management's intent to maintain the FERC-approved capital structure targeting 60% equity and 40% debt for each of our Regulated Operating Subsidiaries. Management does not expect maintaining this targeted capital structure to have an impact on our ability to pay dividends at the current level in the foreseeable future. Each of our subsidiaries, however, is legally distinct from us and has no obligation, contingent or otherwise, to make funds available to us.

2. DEBT

As of December 31, 2015, the maturities of our debt outstanding were as follows:



(In thousands)
2016	$	395,344
2017	50,000
2018	385,000
2019	137,700
2020	200,000
2021 and thereafter	1,150,340
Total	$	2,318,384

Refer to Note 8 to the consolidated financial statements for a description of the ITC Holdings Senior Notes, the ITC Holdings Revolving and Term Loan Credit Agreements, the ITC Holdings Commercial Paper Program and related items.

Based on the borrowing rates obtained from third party lending institutions currently available for bank loans with similar terms and average maturities from active markets, the fair value of the ITC Holdings Senior Notes was $2,059.4 million and $2,126.1 million at December 31, 2015 and 2014, respectively. The total book value of the ITC Holdings Senior Notes, net of discount, was $1,921.3 million and $1,920.7 million at December 31, 2015 and 2014, respectively. At December 31, 2015 and 2014, we had a total of $298.7 million and $214.5 million, respectively, outstanding under our revolving and term loan credit agreements, which are variable rate loans. The fair value of these loans approximates book value based on the borrowing rates currently available for variable rate loans obtained from third party lending institutions. These fair values represent Level 2 under the three-tier hierarchy described in Note 12 to the consolidated financial statements. At December 31, 2015, ITC Holdings had $95.0 million of commercial paper issued and outstanding under the commercial paper program established in 2015. Due to the short-term nature of these financial instruments, the carrying value approximates fair value.

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Covenants

Our debt instruments contain numerous financial and operating covenants that place significant restrictions on certain transactions, such as incurring additional indebtedness, engaging in sale and lease-back transactions, creating liens or other encumbrances, entering into mergers, consolidations, liquidations or dissolutions and paying dividends. In addition, the covenants require us to meet certain financial ratios, such as maintaining certain debt to capitalization ratios. At December 31, 2015, we were not in violation of any debt covenant.

3. RELATED-PARTY TRANSACTIONS

Our related-party transactions during 2015, 2014 and 2013 were as follows:



	Year Ended December 31,
(In millions)	2015		2014		2013
Equity contributions to subsidiaries	$	263.2	$	348.7	$	339.8
Dividends from subsidiaries (a)	185.3		224.2		170.0
Return of capital from subsidiaries (a)	161.1		126.9		96.1

Income taxes paid to ITC Holdings from: (b)
ITCTransmission	$	36.4	$	38.1	$	39.1
MTH	39.0		41.4		30.0
ITC Midwest	31.0		34.3		33.6
ITC Great Plains	14.5		10.6		9.4

____________________________


(a)	Includes ITCTransmission, MTH, ITC Midwest and other subsidiaries.

(b)

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

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized in the City of Novi, State of Michigan, on February 25, 2016.



ITC HOLDINGS CORP.
By:	/s/ JOSEPH L. WELCH
	Joseph L. Welch
	Chairman, President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant and in the capacities and on the dates indicated:



Signature	Title	Date
/s/ JOSEPH L. WELCH	Chairman, President and Chief	February 25, 2016
Joseph L. Welch	Executive Officer (principal executive officer)

/s/ REJJI P. HAYES	Senior Vice President and Chief	February 25, 2016
Rejji P. Hayes	Financial Officer (principal financial
	and accounting officer)

/s/ ALBERT ERNST	Director	February 25, 2016
Albert Ernst

/s/ CHRISTOPHER H. FRANKLIN	Director	February 25, 2016
Christopher H. Franklin

/s/ EDWARD G. JEPSEN	Director	February 25, 2016
Edward G. Jepsen

/s/ DAVID R. LOPEZ	Director	February 25, 2016
David R. Lopez

/s/ HAZEL R. O’LEARY	Director	February 25, 2016
Hazel R. O’Leary

/s/ THOMAS G. STEPHENS	Director	February 25, 2016
Thomas G. Stephens

/s/ GORDON BENNETT STEWART, III	Director	February 25, 2016
Gordon Bennett Stewart, III

/s/ LEE C. STEWART	Director	February 25, 2016
Lee C. Stewart

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EXHIBITS

The following exhibits are filed as part of this report or filed previously and incorporated by reference to the filing indicated. Our SEC file number is 001-32576.



Exhibit No.			Description of Exhibit

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

3.1			Amended and Restated Articles of Incorporation of the Registrant, as amended (filed with Registrant’s 2013 Form 10-K)

3.2			Fifth Amended and Restated Bylaws of Registrant dated as of February 24, 2015 (filed with Registrant’s 2014 Form 10-K)

4.1			Form of Certificate of Common Stock (filed with Registrant’s Registration Statement on Form S-1, as amended, Reg. No. 333-123657)

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

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

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

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

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

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

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

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

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

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

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

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

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

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Exhibit No.		Description of Exhibit



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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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Exhibit No.		Description of Exhibit




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

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

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

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

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

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

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

10.52			Amendment and Restatement of the April 1, 2001 Operating Agreement by and between Michigan Electric Transmission Company and Consumers Energy Company, effective May 1, 2002 (filed with Registrant’s Form 10-Q for the quarter ended September 30, 2006)

10.53			Amendment and Restatement of the April 1, 2001 Purchase and Sale Agreement for Ancillary Services between Consumers Energy Company and Michigan Electric Transmission Company, effective May 1, 2002 (filed with Registrant’s Form 10-Q for the quarter ended September 30, 2006)

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

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

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

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

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

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

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

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

*10.98			ITC Holdings Corp. Employee Stock Purchase Plan, as amended and restated May 26, 2011 (filed with Registrant’s Form 8-K on June 1, 2011)

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

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

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

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

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

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Exhibit No.		Description of Exhibit



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

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

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

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

10.123			ITC Holdings 2013 Term Loan Credit Agreement, dated as of December 20, 2013, among ITC Holdings Corp., the various financial institutions and other persons from time to time parties thereto as lenders, Wells Fargo Bank, National Association, as administrative agent for the Lenders, Wells Fargo Securities, LLC, J.P. Morgan Securities LLC and Merrill Lynch, Pierce, Fenner & Smith Incorporated as joint lead arrangers and joint bookrunners, Bank of America, N.A., as documentation agent, and JPMorgan Chase Bank, N.A., as syndication agent (filed with Registrant's Form 8-K on December 20, 2013)

10.124			METC 2014 Term Loan Credit Agreement dated as of January 31, 2014, among Michigan Electric Transmission Company, LLC, the various financial institutions and other persons from time to time parties thereto as lenders, and Goldman Sachs Bank USA, as administrative agent for the Lenders and as sole lead arranger and sole bookrunner (filed with Registrant’s Form 8-K on January 31, 2014)

10.125			Amended and Restated Large Interconnection Agreement, entered into by the Midcontinent Independent System Operator, Inc., Interstate Power and Light Company and ITC Midwest dated August 6, 2013 (filed with Registrant’s 2013 Form 10-K)

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

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

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

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

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

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

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

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

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Exhibit No.		Description of Exhibit



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

*10.137			Employment Agreement between ITC Holdings Corp. and Rejji P. Hayes, effective as of December 21, 2012 (filed with Registrant’s Form 10-Q for quarter ended September 30, 2014)

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

*10.139			ITC Holdings Corp. Employee Stock Purchase Plan, as amended May 21, 2014 (filed with Registrant’s Form 10-Q for quarter ended June 30, 2014)

*10.140			Summary of Annual Incentive Plan (2015) (filed with Registrant’s Form 10-Q for the quarter ended March 30, 2015)

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

10.142			Amendment and Restatement of the Distribution - Transmission Interconnection Agreement by and between Michigan Electric Transmission Company, LLC and Consumers Energy Company, effective January 1, 2015 (filed with Registrant’s Form 10-Q for the quarter ended March 30, 2015)

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

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

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

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

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

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

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

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

10.151			Amended and Restated Generator Interconnection Agreement by and among Michigan Electric Transmission Company, LLC, Consumers Energy Company and the Midcontinent Independent System Operator, Inc., dated as of September 30, 2015 (filed with Registrant’s Form 10-Q for the quarter ended September 30, 2015)

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

10.153			Second Amended Distribution-Transmission Interconnection Agreement, by and between ITC Midwest LLC, as Transmission Owner and Interstate Power and Light Company, as Local Distribution Company, effective as of February 21, 2015

10.154			Summary of Stock Ownership Guidelines, effective August 16, 2006, as amended November 18, 2015, for Registrant’s Directors and Executive Officers

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

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

21			List of Subsidiaries

23.1			Consent of Deloitte & Touche LLP relating to the Registrant and subsidiaries

116

Table of Contents



Exhibit No.		Description of Exhibit



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

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

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

101.INS			XBRL Instance Document

101.SCH			XBRL Taxonomy Extension Schema

101.CAL			XBRL Taxonomy Extension Calculation Linkbase

101.DEF			XBRL Taxonomy Extension Definition Database

101.LAB			XBRL Taxonomy Extension Label Linkbase

101.PRE			XBRL Taxonomy Extension Presentation Linkbase

____________________________



*		Management contract or compensatory plan or arrangement.

117

Large accelerated filer þ

Accelerated filer o

Non-accelerated filer o

Smaller Reporting Company o

(Do not check if a smaller reporting company)