ITC Holdings Corp. - FORM 10-K

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EXCEL - IDEA: XBRL DOCUMENT - ITC Holdings Corp.	Financial_Report.xls
EX-21 - LIST OF SUBSIDIARIES - ITC Holdings Corp.	itc20141231ex_21.htm
EX-32 - CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 - SECTION 906 OF SOX - ITC Holdings Corp.	itc20141231ex_32.htm
EX-31.1 - CERTIFICATION OF CEO PURSUANT TO RULE 13A-14 - SECTION 302 OF SOX - ITC Holdings Corp.	itc20141231ex_311.htm
EX-12.1 - RATIO OF EARNINGS TO FIXED CHARGES - ITC Holdings Corp.	itc20141231ex_121.htm
EX-31.2 - CERTIFICATION OF CFO PURSUANT TO RULE 13A-14 - SECTION 302 OF SOX - ITC Holdings Corp.	itc20141231ex_312.htm
EX-23.1 - CONSENT OF DELOITTE & TOUCHE LLP - ITC Holdings Corp.	itc20141231ex_231.htm
EX-3.2 - FIFTH AMENDED AND RESTATED BYLAWS - ITC Holdings Corp.	itc20141231ex3_2.htm

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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, 2014



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, 2014 was approximately $5.6 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 20, 2015 was 155,196,031.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Registrant’s definitive Proxy Statement for the Registrant’s 2015 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, 2014

INDEX



		Page
PART I		5
Item 1.	Business	5
Item 1A.	Risk Factors	16
Item 1B.	Unresolved Staff Comments	22
Item 2.	Properties	23
Item 3.	Legal Proceedings	24
Item 4.	Mine Safety Disclosures	24

PART II		25
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	25
Item 6.	Selected Financial Data	27
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	28
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	46
Item 8.	Financial Statements and Supplementary Data	48
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	97
Item 9A.	Controls and Procedures	97
Item 9B.	Other Information	97

PART III		97
Item 10.	Directors, Executive Officers and Corporate Governance	97
Item 11.	Executive Compensation	97
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	98
Item 13.	Certain Relationships and Related Transactions, and Director Independence	98
Item 14.	Principal Accountant Fees and Services	98

PART IV		99
Item 15.	Exhibits and Financial Statement Schedules	99
Signatures		106
Exhibits		107

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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 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, to reduce transmission constraints and to 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 to 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.”

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 investment program totaling $4.5 billion for the period 2014 through 2018 of which $794.0 million has been invested through December 31, 2014. 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 $2.2 billion from 2014 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 $1.2 billion from 2014 through 2018 to develop and build regional transmission infrastructure to address system needs.

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 $800 million in our portions of these four MVPs from 2014 through 2018. The Thumb Loop Project is located in ITCTransmission’s region and 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 Michigan. We estimate ITCTransmission will invest a total of approximately $510 million in the project which is currently anticipated to be completed in 2015. Through December 31, 2014, ITCTransmission has invested $465.8 million in the Thumb Loop Project.

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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

We expect to invest approximately $1.1 billion from 2014 through 2018 to construct various development projects, or portions thereof, that are expected to result from the competitive process established pursuant to FERC Order No. 1000 (“Order 1000”) described below and through other initiatives 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 general 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 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”),

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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 and MECS LBA area emergency procedure implementation and coordination. ITC Midwest and ITC Great Plains are not responsible for LBA functions for their respective assets.

Operating Contracts

Our Regulated Operating Subsidiaries have various operating contracts, including numerous interconnection agreements with generation and transmission providers that address terms and conditions of interconnection. The following significant agreements exist at our Regulated Operating Subsidiaries:

ITCTransmission

DTE Electric operates the electric distribution system to which ITCTransmission’s transmission system connects. A set of three operating contracts sets forth the terms and conditions related to DTE Electric’s and ITCTransmission’s ongoing working relationship. These contracts include the following:

Master Operating Agreement. The Master Operating Agreement (the “MOA”), dated as of February 28, 2003, governs the primary day-to-day operational responsibilities of ITCTransmission and DTE Electric and will remain in effect until terminated by mutual agreement of the parties (subject to any required FERC approvals) unless earlier terminated pursuant to its terms. The MOA identifies the control area coordination services that ITCTransmission is obligated to provide to DTE Electric. The MOA also requires DTE Electric to provide certain generation-based support services to ITCTransmission.

Generator Interconnection and Operation Agreement. DTE Electric and ITCTransmission entered into the Generator Interconnection and Operation Agreement (the “GIOA”), dated as of February 28, 2003, in order to establish, re-establish and maintain the direct electricity interconnection of DTE Electric’s electricity generating assets with ITCTransmission’s transmission system for the purposes of transmitting electric power from and to the electricity generating facilities. Unless otherwise terminated by mutual agreement of the parties (subject to any required FERC approvals), the GIOA will remain in effect until DTE Electric elects to terminate the agreement with respect to a particular unit or until a particular unit ceases commercial operation.

Coordination and Interconnection Agreement. The Coordination and Interconnection Agreement (the “CIA”), dated as of February 28, 2003, governs the rights, obligations and responsibilities of ITCTransmission and DTE Electric regarding, among other things, the operation and interconnection of DTE Electric’s distribution system and ITCTransmission’s transmission system, and the construction of new facilities or modification of existing facilities. Additionally, the CIA allocates costs for operation of supervisory, communications and metering equipment. The CIA will remain in effect until terminated by mutual agreement of the parties (subject to any required FERC approvals).

METC

Consumers Energy operates the electric distribution system to which METC’s transmission system connects. METC is a party to a number of operating contracts with Consumers Energy that govern the operations and maintenance of its transmission system. These contracts include the following:

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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 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.

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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 amended and restated as of March 1, 2013, 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 amended as of May 2, 2014, 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, 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 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

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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 amended June 20, 2013, 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.

Maintenance Agreement. Midwest Energy, Inc. (“Midwest Energy”) and ITC Great Plains entered into a maintenance agreement (the “Midwest Energy Agreement”) dated as of June 25, 2012, pursuant to which Midwest Energy agreed to perform various field operations and maintenance service related to certain ITC Great Plains facilities. The Midwest Energy Agreement had an initial term of three years with automatic three-year renewals unless terminated (1) due to a material breach by the non-terminating party following notice and failure to cure or (2) by mutual consent of the parties. In December 2014, ITC Great Plains and Midwest Energy mutually agreed to terminate the Midwest Energy Agreement. Services will continue to be provided through the effective termination date of June 24, 2015.

Regulatory Environment

Many regulators and public policy makers support the need for further investment in the transmission grid. The growth in 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 fines of up to $1.0 million per day. 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 and the requirement of the FERC to review and approve mergers and consolidations involving utility assets and utility 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 sale 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.

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 have made multiple compliance filings with the FERC to implement these requirements. Certain of the new provisions relating to the requirements described above have been approved but others remain under review by the FERC.

Order 1000 could potentially lead to greater competition for certain future transmission projects, including within our current operating areas. We are currently exploring opportunities resulting from Order 1000 within MISO and SPP as well as other RTOs.

Revenue Requirement Calculations and Cost Sharing for Projects with Regional Benefits

The cost based formula rates used by our Regulated Operating Subsidiaries continue to evolve to 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 these separate calculations 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 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 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 22.2%, 24.2% and 29.0%, respectively, of our consolidated billed revenues for the year ended

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December 31, 2014. 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 2012 revenue accruals and deferrals and exclude any amounts for the 2014 revenue accruals and deferrals that were included in our 2014 operating revenues, but will not be billed to our customers until 2016. 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 is responsible for billing and collecting the majority of our transmission services provided by our MISO Regulated Operating Subsidiaries and independently administers the transmission tariff in the MISO service territory. As the billing agent for our MISO Regulated Operating Subsidiaries, MISO independently bills DTE Electric, Consumers Energy, IP&L and other customers on a monthly basis and collects fees for the use of our MISO Regulated Operating Subsidiaries’ transmission systems.

SPP is responsible for billing and collection for the transmission services provided by ITC Great Plains and independently administers the transmission tariff in the SPP service territory. As the billing agent for ITC Great Plains, SPP independently bills customers on a monthly basis and collects fees for the use of ITC Great Plains’ 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, therefore, effectively has no competitors 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 we are best able to develop these projects in a non-discriminatory manner. However, there are no assurances we will be selected to develop projects that other entities are also pursuing.

Employees

As of December 31, 2014, we had 587 employees. We consider our relations with our employees to be good.

Environmental Matters

Our operations 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 hazardous materials and of solid and hazardous wastes, and impose obligations to investigate and remediate contamination in certain circumstances. Liabilities for failing to investigate or remediate 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 at 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 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 and compliance with those requirements more expensive. We are not aware of any specific developments that would increase our costs for such compliance

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in a manner that would be expected to have a material effect on our results of operations, financial position or liquidity.

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

Some properties in which we have an ownership interest or at which we operate are, and others are suspected of being, affected by environmental contamination. We are not aware of any claims pending or threatened against us with respect to environmental contamination, or of any investigation or remediation of contamination at any 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, if such a relationship is established or accepted, the liabilities and costs imposed on our business could be significant. We are not aware of any claims pending or threatened 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. You can access free of charge on our web site 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. These reports are available as soon as practicable after they are electronically filed with the Securities and Exchange Commission (the “SEC”). Also on our web site are 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, Chief Financial Officer and Treasurer. 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 web site within the required periods. The information on our web site 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.

You may also read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington DC, 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. The address is http://www.sec.gov.

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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 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, the approved targeted capital structures and the data inputs provided by our Regulated Operating Subsidiaries for calculation of each year’s rate, 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, end-use consumers and entities supplying electricity to end-use consumers may 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 after the date that a Section 206 challenge is filed, 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 are seeking a FERC order reducing the base rate of return on equity used in our formula transmission rate from 12.38% to 9.15%, capping the equity component of MISO transmission owners’ capital structures, which would reduce the targeted equity component of ITCTransmission’s, METC’s and ITC Midwest’s capital structures from 60% to 50%, and terminating the return on equity adders approved for ITCTransmission and METC. On October 16, 2014, the FERC issued an order rejecting this complaint as to ITCTransmission's and METC’s equity adders and MISO transmission owner capital structures. A hearing was ordered on the complaint's allegations as to the base rate of return on equity for all MISO transmission owners. In the event a refund is required upon resolution of the complaint, the refund effective date would be November 12, 2013. Also, on February 12, 2015, an additional complaint was filed under Section 206 of the FPA seeking a FERC order reducing the regional base ROE rate used in our MISO Regulated Operating Subsidiaries’ formula transmission rates to 8.67%, to be effective for the period beginning February 12, 2015. An unfavorable resolution of the November 2013 complaint in excess of the amount accrued for the refund liability, or the February 2015 complaint 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 therefore our 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 assure you 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, the amounts of which 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 potentially 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

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or other transmission development entities may compete with us by deciding to pursue capital projects that we are pursuing.

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

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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 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 66.8% of ITCTransmission’s total billed revenues for the year ended December 31, 2014 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 & Poor’s Ratings Services and Moody’s Investors Services, Inc., respectively. Similarly, Consumers Energy accounted for approximately 77.4% of METC’s total billed revenues for the year ended December 31, 2014 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 & Poor’s Ratings Services and Moody’s Investors Service, Inc., respectively. Further, IP&L accounted for approximately 84.2% of ITC Midwest’s total billed revenues for the year ended December 31, 2014 and is expected to constitute the majority of ITC Midwest’s revenues for the foreseeable future. IP&L is rated A-/stable and A3/stable by Standard & Poor’s Ratings Services and Moody’s Investors Service, Inc., respectively. These percentages of total billed revenues of DTE Electric, Consumers Energy and IP&L include the collection of 2012 revenue accruals and deferrals and exclude any amounts for the 2014 revenue accruals and deferrals that were included in our 2014 operating revenues, but will not be billed to our customers until 2016.

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 hazardous materials and of solid and hazardous wastes, and impose obligations to investigate and remediate contamination in certain circumstances. Liabilities to investigate or remediate 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 at 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 each will continue to do so in the future. Failure to comply with the extensive environmental laws and regulations applicable to each 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 assure you 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. Penalty

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amounts range from $1,000 to a maximum of $1.0 million per day, depending on the severity of the violation. Non-monetary sanctions include potential limitations on the violator’s activities or operation and placing the violator on a watchlist for major violators. Despite our best efforts to comply and the implementation of a compliance program intended to ensure reliability, there can be no assurance that violations will not occur that would result in material penalties or sanctions. If any of our subsidiaries were to violate the NERC reliability standards, even unintentionally, in any material way, any penalties or sanctions imposed against us could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Certain of our subsidiaries are also subject to requirements under Sections 203 and 205 of the FPA for approval of transactions; reporting, recordkeeping and accounting requirements; and for filing contracts related to the provision of jurisdictional services. Under FERC policy, failure to file jurisdictional agreements on a timely basis may result in foregoing the time value of revenues collected under the agreement, but not to the point where a loss would be incurred. The failure to obtain timely approval of transactions subject to FPA Section 203, or to comply with applicable reporting, recordkeeping or accounting requirements under FPA Section 205, could subject 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, the 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.

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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 and revolving and term loan credit agreements that we rely on as sources of capital and liquidity. This financing strategy can have several important consequences, including, but not limited to, the following:


•	If future cash flows are insufficient, we may not be able to make principal or interest payments on our debt obligations, which could result in the occurrence of an event of default under one or more of those debt instruments.


•	We may need to increase our indebtedness in order to make the capital expenditures and other expenses or investments planned by us.

•

Our indebtedness has the general effect of reducing our flexibility to react to changing business and economic conditions insofar as they affect our financial condition 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 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 and revolving and term loan credit agreements, 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.

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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 borrowing costs. A rating downgrade could also increase the interest we pay 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 a majority 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.

ITEM 1B. UNRESOLVED STAFF COMMENTS.

None.

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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.

ITCTransmission owns the assets of a transmission system and related assets, including:


•	approximately 3,000 circuit miles of overhead and underground transmission lines rated at voltages of 120 kV to 345 kV;


•	approximately 18,300 transmission towers and poles;


•	station assets, such as transformers and circuit breakers, at 179 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 100 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 271 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;

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•	other transmission equipment necessary to safely operate the system (e.g., monitoring and metering equipment);


•	warehouses and related equipment; and


•	associated land held in fee, rights of way and easements.

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 1,900 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 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 symbol “ITC”. As of February 20, 2015, there were approximately 802 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 2014 and 2013, as reported on the NYSE, and the cash dividends per share paid during the periods indicated.



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

Year Ended December 31, 2013	High		Low		Dividends
Quarter ended December 31, 2013	$	35.58	$	29.92	$	0.1417
Quarter ended September 30, 2013	33.11		28.60		0.1417
Quarter ended June 30, 2013	31.23		28.24		0.1258
Quarter ended March 31, 2013	29.80		25.54		0.1258

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 and the proceeds raised from the sale of debt and equity securities. 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 taking into account the subsidiaries’ funding requirements, the terms of the subsidiaries’ indebtedness, the regulations of the FERC under FPA and applicable state laws. The debt agreements to which we are parties 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 we are in default under our term loan credit facility. 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.

On February 6, 2014, our board of directors declared a three-for-one split of our common stock to be accomplished by means of a stock distribution. The additional shares were distributed on February 28, 2014, to the shareholders of record on February 18, 2014. The share and per share data in this Form 10-K reflect this stock split. See further discussion in Note 13 to the consolidated financial statements.

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.

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, 2014:



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 2014	771	$	36.59	—	$	146.0
November 2014	872	37.99		—	146.0
December 2014	653,358	36.56		651,120	120.0
Total	655,001	$	36.57	651,120

____________________________


(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 to us upon the vesting of restricted stock.

(2)

In April 2014, our board of directors authorized a share repurchase program for up to $250.0 million of common stock, which expires in December 2015. Pursuant to such authorization, on June 19, 2014, ITC Holdings entered into an accelerated share repurchase agreement with JP Morgan Chase (“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 ASR program. On December 22, 2014, the ASR program was settled for $130.0 million and ITC Holdings received an additional 651,120 shares as determined by the volume-weighted average share price during the term of the ASR program less an agreed upon discount and adjusted for the initial share delivery. See Note 13 to the consolidated financial statements for detailed discussion on the 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)	2014			2013			2012			2011			2010
OPERATING REVENUES (a) (b)	$	1,023,048		$	941,272		$	830,535		$	757,397		$	696,843
OPERATING EXPENSES
Operation and maintenance	111,623			112,821			121,941			129,288			126,528
General and administrative (c)	115,031			149,109			112,091			82,790			78,120
Depreciation and amortization	128,036			118,596			106,512			94,981			86,976
Taxes other than income taxes	76,534			65,824			59,701			53,430			48,195
Other operating income and expense — net	(1,005		)	(1,139		)	(769		)	(844		)	(297		)
Total operating expenses	430,219			445,211			399,476			359,645			339,522
OPERATING INCOME	592,829			496,061			431,059			397,752			357,321
OTHER EXPENSES (INCOME)
Interest expense	186,636			168,319			155,734			146,936			142,553
Allowance for equity funds used during construction	(20,825		)	(30,159		)	(23,000		)	(16,699		)	(13,412		)
Loss on extinguishment of debt	29,205			—			—			—			—
Other income	(1,103		)	(1,038		)	(2,401		)	(2,881		)	(2,340		)
Other expense	4,511			6,571			4,218			3,962			2,588
Total other expenses (income)	198,424			143,693			134,551			131,318			129,389
INCOME BEFORE INCOME TAXES	394,405			352,368			296,508			266,434			227,932
INCOME TAX PROVISION	150,322			118,862			108,632			94,749			82,254
NET INCOME	$	244,083		$	233,506		$	187,876		$	171,685		$	145,678

Basic earnings per share (d)	$	1.56		$	1.49		$	1.22		$	1.12		$	0.96
Diluted earnings per share (d)	$	1.54		$	1.47		$	1.20		$	1.10		$	0.95
Dividends declared per share (d)	$	0.610		$	0.535		$	0.487		$	0.458		$	0.437



	ITC Holdings and Subsidiaries
	As of December 31,
(In thousands)	2014			2013			2012			2011			2010
BALANCE SHEET DATA:
Cash and cash equivalents	$	27,741		$	34,275		$	26,187		$	58,344		$	95,109
Working capital (deficit)	(276,198		)	(307,841		)	(805,085		)	(113,939		)	69,338
Property, plant and equipment — net	5,496,875			4,846,526			4,134,579			3,415,823			2,872,277
Goodwill	950,163			950,163			950,163			950,163			950,163
Total assets	6,974,089			6,282,243			5,564,809			4,823,366			4,307,873
Debt:
ITC Holdings	2,135,244			1,881,918			1,689,619			1,459,599			1,459,178
Regulated Operating Subsidiaries	1,968,342			1,730,194			1,457,608			1,185,423			1,037,718
Total debt	4,103,586			3,612,112			3,147,227			2,645,022			2,496,896
Total stockholders’ equity	$	1,669,557		$	1,613,732		$	1,414,855		$	1,258,892		$	1,117,433



	ITC Holdings and Subsidiaries
	Year Ended December 31,
(In thousands)	2014		2013		2012		2011		2010
CASH FLOWS DATA:
Expenditures for property, plant and equipment	$	733,145	$	821,588	$	802,763	$	556,931	$	388,401

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____________________________


(a)	During 2014, we recognized an aggregate estimated regulatory liability for the potential refunds relating to the rate of return on equity and capital structure complaint as described in Note 16 to the consolidated financial statements, which resulted in a reduction in operating revenues of $46.9 million.


(b)	During 2012, we initially recognized the FERC audit refund liability, which resulted in a reduction in operating revenues of $11.0 million. See Note 16 to the consolidated financial statements for discussion on the FERC audit refund.


(c)	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.


(d)	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.



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 and the outlook for our business and the electric transmission industry 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” and similar phrases. These forward-looking statements are based upon assumptions our management believes are reasonable. Such forward-looking statements are subject to 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.

Because our forward-looking statements are based on estimates and assumptions that are subject to significant business, economic and competitive uncertainties, many of which are beyond our control or are subject to change, actual results could be materially different and any or all of our forward-looking statements may turn out to be wrong. 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, to reduce transmission constraints and to upgrade the transmission networks to support new generating resources interconnecting to our transmission systems. We also are pursuing development projects not within our existing systems, which are likewise intended to improve overall grid reliability, reduce transmission constraints and facilitate interconnections of new generating resources, as well as enhance competitive wholesale electricity markets.

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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 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 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, 2014 or may affect future results include:

•

Our capital investments of $793.5 million at our Regulated Operating Subsidiaries ($252.3 million, $126.4 million, $286.3 million and $128.5 million at ITCTransmission, METC, ITC Midwest and ITC Great Plains, respectively) for the year ended December 31, 2014, 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 2014 and 2013 to fund capital investment at our Regulated Operating Subsidiaries, resulting in higher interest expense;


•	Debt maturing within one year and the interest rates associated with the additional financing required as discussed in Note 8 to the consolidated financial statements;


•	Loss on extinguishment of debt of $29.2 million related to the tender of ITC Holdings Senior Notes as described in Note 8 to the consolidated financial statements;


•	Recognition of estimated contingent liability of $47.8 million for the potential refunds, including interest, relating to the rate of return on equity and capital structure complaint as described in Note 16 to the consolidated financial statements; and


•	Repurchases of common stock of $130.0 million during 2014 under the ASR program as described in Note 13 to the consolidated financial statements.

These items are discussed in more detail throughout Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Cost-Based Formula Rates with True-Up Mechanism

Our Regulated Operating Subsidiaries calculate their revenue requirements using cost-based formula 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 to calculate 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 rather than a lagging basis. 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

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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, 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 affected by many variables, but is generally impacted by weather and economic conditions and is 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 general trend of increases in revenues and earnings for our Regulated Operating Subsidiaries over the long term. The primary factor that is expected to continue to increase our actual revenue requirements 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

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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 to improve system accessibility for all generation resources. The FERC requires compliance with certain reliability standards and may take enforcement actions against violators, including fines of up to $1.0 million per day. 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 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 to increase import capacity to meet changes in peak electrical demand; (3) relieve congestion in the transmission systems; and (4) achieve state and federal policy goals, such as renewable generation portfolio standards. The following table shows our expected and actual capital investment for each of the Regulated Operating Subsidiaries and our development initiatives:



			Actual Capital		Forecasted Capital
	Long-term Capital		Investment for the		Investment for the
	Investment Program		Year Ended		Year Ending
Source of Investment	2014-2018		December 31, 2014 (a)		December 31, 2015
(In millions)
ITCTransmission	$	647	$	252.3	$170 — 200
METC	546		126.4		150 — 170
ITC Midwest (b)	1,991		286.3		380 — 405
ITC Great Plains	194		128.5		10 — 25
Development and other (c)	1,122		0.5		0 — 10
Total	$	4,500	$	794.0	$710 — 810

____________________________

(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 expenditures but not included in capital investment until transferred to construction work in progress, among other factors.


(b)	ITC Midwest’s investment program includes the 2011 MISO MVPs as discussed below under “Capital Project Updates and Other Recent Developments — North Central Region Development.”


(c)	Refer to “Item 1 Business — Development of Business — Development Projects” for discussion on our development projects.

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 and variances between estimated and actual costs of construction contracts awarded. 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.

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Capital Project Updates and Other Recent Developments

Thumb Loop Project

The Thumb Loop Project, an additional MVP, is located in ITCTransmission’s region and 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. Construction activities commenced for the Thumb Loop Project in 2012. Phase 1 of the Thumb Loop Project, consisting of 62 miles of 345 kV transmission facilities has been placed into service. Phase 2, consisting of approximately 20 miles, was placed into service in May 2014. Through December 31, 2014, ITCTransmission has invested $465.8 million in the Thumb Loop Project. We estimate ITCTransmission will invest a total of approximately $510 million in the project, which is currently anticipated to be completed in 2015.

ITC Great Plains

Kansas V-Plan Project

The Kansas V-Plan Project is a 200-mile transmission line that runs between Spearville and Wichita, Kansas. ITC Great Plains was responsible for constructing an approximately 120 mile portion of the project from Spearville to Medicine Lodge, Kansas. ITC Great Plains commenced construction during 2012 and the project was placed in-service in 2014. Through December 31, 2014, ITC Great Plains invested $315.0 million in the Kansas V-Plan Project and does not expect the remaining investment to be material.

Regulatory Assets

As of December 31, 2014, we have recorded approximately $14.1 million of regulatory assets for start-up, development and pre-construction expenses, including associated interest carrying charges, incurred by ITC Great Plains, which include certain costs incurred for the KETA and the Kansas V-Plan Projects prior to construction. Based on ITC Great Plains’ FERC application under which authority to recognize these regulatory assets was sought and the related FERC order granting such authority, ITC Great Plains made a filing with the FERC under Section 205 of the FPA in May 2013 to recover these start-up, development and pre-construction expenses, including associated carrying charges, in future rates. If FERC authorization is received, ITC Great Plains will include the unamortized balance of the regulatory assets in its rate base and will amortize them over a 10-year period beginning at the later of the project in-service date or the FERC authorization date.

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 will be constructed by ITC Midwest. We currently estimate we will invest approximately $800 million in our portions of the MVPs from 2014 through 2018.

Development Bonuses

During 2014, 2013 and 2012, we recognized general and administrative expenses of $2.7 million, $3.4 million and $2.9 million, respectively, for bonuses for certain development projects, including the successful completion of certain milestones relating to projects at ITC Great Plains. Development-related bonuses may be authorized and awarded in the future related to development projects.

Rate of Return on Equity and Capital Structure Complaint

In November 2013, certain parties filed a joint complaint with the FERC under Section 206 of the FPA (the “Complaint”), requesting that the FERC find the current 12.38% MISO regional base ROE rate 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 regional base ROE rate 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

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seek dismissal of the Complaint for its failure to satisfy the requirements of FPA Section 206 and the FERC’s accompanying Rules, or denial of the Complaint on the merits, with prejudice.

On October 16, 2014, FERC granted the complainants’ request in part by setting the MISO regional base ROE rate for hearing and settlement procedures, while denying all other aspects of the Complaint. FERC found the complainants failed to show that the use of actual or FERC-approved capital structures that include more than 50% equity are unjust and unreasonable. FERC also denied the request to terminate ITCTransmission’s and METC’s ROE incentives. The order again reiterates 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 issued an order which terminated settlement procedures and set the matter for hearing. The order established a schedule for the proceeding for a hearing within 32 weeks of the order and an initial decision within 47 weeks of the order. We expect FERC to establish a new base ROE rate to determine any refund liability for the period of November 12, 2013 through February 11, 2015 (the “Initial Refund Period”). The new base ROE rate 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 believe it is probable that a refund will be required for the Initial Refund Period, and the estimated range of refunds is expected to be from $47.8 million to $88.1 million for the period from November 12, 2013 through December 31, 2014. During the fourth quarter of 2014, ITCTransmission, METC, and ITC Midwest recorded an aggregate estimated regulatory liability of $47.8 million for the potential refunds as of December 31, 2014, as there is no best estimate within the range of refunds. This amount has been recorded as a reduction of revenues of $46.9 million and an increase in interest expense of $0.9 million in the consolidated statements of operations, and resulted in an estimated after-tax reduction of net income of $28.9 million for the year ended December 31, 2014. Based on the estimated range of refunds identified above, we believe that it is reasonably possible that this matter could result in an additional pre-tax refund of up to $40.3 million (or a $24.4 million after-tax reduction of net income) in excess of the amount recorded as of December 31, 2014. It is also possible the outcome of this matter could differ from the estimated range of losses and materially affect our results of operations due to the uncertainty of the calculation of an authorized ROE rate along with the zone of reasonableness under the newly adopted two-step DCF methodology, which is subject to significant discretion by the FERC.

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. These adders would be applied to METC’s and ITC Midwest’s base ROE rates in establishing their total authorized ROE rates, subject to the limitations of the top end of any zone of reasonableness that is established. Additionally, on January 30, 2015, ITC Midwest filed a request with FERC under FPA Section 205 for authority to include a 100 basis point incentive adder for independent transmission ownership, which is currently authorized for ITCTransmission and METC. Finally, on February 12, 2015, an additional complaint was filed under Section 206 of the FPA seeking a FERC order reducing the regional base ROE rate used in our MISO Regulated Operating Subsidiaries’ formula transmission rates to 8.67%, to be effective for the period beginning February 12, 2015.

Stock Split

On February 6, 2014, our board of directors declared a three-for-one split of our common stock that occurred on February 28, 2014. The share and per share data in this Form 10-K reflect this stock split. See further discussion in Note 13 to the consolidated financial statements.

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 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

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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 consist of both billed network revenues and accrued or deferred revenues 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 — Revenue Recognition under Cost-Based Formula Rates with True-Up Mechanisms” for a discussion of revenue recognition relating to network revenues. The monthly network revenues billed to customers using the transmission facilities of our MISO Regulated Operating Subsidiaries are the result of a calculation which can be simplified into the following:


(1)	multiply the network load measured in kW achieved during the one hour of monthly peak usage for our transmission systems by the appropriate monthly tariff rate by 12 by the number of days in that month; and


(2)	divide the result by 365.

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. Our annual projected project revenue requirements at ITC Great Plains are billed ratably each month and therefore peak usage does not impact its billed network transmission revenues.

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. Regional cost sharing revenues consist of both billed regional cost sharing revenues and accrued or deferred revenues as a result of our accounting under our cost-based formula rates that contain a true-up mechanism. The amount of the regional cost sharing revenue accruals (deferrals) is estimated for each reporting period until such time as the regional cost sharing formula rate templates based on actual costs are completed for each of our Regulated Operating Subsidiaries during the following year. A portion of regional cost sharing revenues is not subject to a direct true-up but instead 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. Beginning in 2013, certain scheduling, control and dispatch revenues became subject to a true-up mechanism at our MISO Regulated Operating Subsidiaries that ensures that our MISO Regulated Operating Subsidiaries recover their allowed costs.

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 are a reduction to gross revenue requirement when calculating net revenue requirement under our cost-based formula rates.

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Operating Expenses

Operation and Maintenance Expenses consist primarily of the costs of contractors to operate and maintain our transmission systems and costs for 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 is 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)	2014			2013			(Decrease)			(Decrease)	2012			(Decrease)			(Decrease)
OPERATING REVENUES	$	1,023,048		$	941,272		$	81,776		8.7%	$	830,535		$	110,737		13.3%
OPERATING EXPENSES
Operation and maintenance	111,623			112,821			(1,198		)	(1.1)%	121,941			(9,120		)	(7.5)%
General and administrative	115,031			149,109			(34,078		)	(22.9)%	112,091			37,018			33.0%
Depreciation and amortization	128,036			118,596			9,440			8.0%	106,512			12,084			11.3%
Taxes other than income taxes	76,534			65,824			10,710			16.3%	59,701			6,123			10.3%
Other operating income and expenses — net	(1,005		)	(1,139		)	134			(11.8)%	(769		)	(370		)	48.1%
Total operating expenses	430,219			445,211			(14,992		)	(3.4)%	399,476			45,735			11.4%
OPERATING INCOME	592,829			496,061			96,768			19.5%	431,059			65,002			15.1%
OTHER EXPENSES (INCOME)
Interest expense	186,636			168,319			18,317			10.9%	155,734			12,585			8.1%
Allowance for equity funds used during construction	(20,825		)	(30,159		)	9,334			(30.9)%	(23,000		)	(7,159		)	31.1%
Loss on extinguishment of debt	29,205			—			29,205			n/a	—			—			n/a
Other income	(1,103		)	(1,038		)	(65		)	6.3%	(2,401		)	1,363			(56.8)%
Other expense	4,511			6,571			(2,060		)	(31.3)%	4,218			2,353			55.8%
Total other expenses (income)	198,424			143,693			54,731			38.1%	134,551			9,142			6.8%
INCOME BEFORE INCOME TAXES	394,405			352,368			42,037			11.9%	296,508			55,860			18.8%
INCOME TAX PROVISION	150,322			118,862			31,460			26.5%	108,632			10,230			9.4%
NET INCOME	$	244,083		$	233,506		$	10,577		4.5%	$	187,876		$	45,630		24.3%

Operating Revenues

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 contingent liability for return on equity complaint	(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 estimated contingent liability for potential refunds relating to the return on equity complaint resulted in a reduction to operating revenues of $46.9 million during the fourth quarter of 2014 as described in

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Note 16 to the consolidated financial statements. We are not able to estimate whether any required refunds 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.

Year ended December 31, 2013 compared to year ended December 31, 2012

The following table sets forth the components of and changes in operating revenues:



												Percentage
	2013				2012				Increase			Increase
(In thousands)	Amount		Percentage		Amount		Percentage		(Decrease)			(Decrease)
Network revenues	$	726,161	77.1	%	$	669,048	80.6	%	$	57,113		8.5	%
Regional cost sharing revenues	177,364		18.8	%	122,626		14.8	%	54,738			44.6	%
Point-to-point	17,312		1.8	%	17,439		2.1	%	(127		)	(0.7	)%
Scheduling, control and dispatch	12,226		1.3	%	15,077		1.8	%	(2,851		)	(18.9	)%
Other	8,209		1.0	%	6,345		0.7	%	1,864			29.4	%
Total	$	941,272	100.0	%	$	830,535	100.0	%	$	110,737		13.3	%

Network revenues increased due primarily to higher net revenue requirements at our Regulated Operating Subsidiaries during the year ended December 31, 2013 as compared to 2012. Higher net revenue requirements were due primarily to higher rate bases associated with higher balances of property, plant and equipment in-service in 2013 and lower revenues in 2012 resulting from the initial recognition of the FERC audit refund as described in Note 16 to the consolidated financial statements.

Regional cost sharing revenues increased due primarily to additional capital projects that have been identified by MISO as eligible for regional cost sharing and these projects being placed in-service.

Scheduling, control and dispatch revenues decreased due primarily to the true-up mechanism initially implemented in 2013.

Operating revenues for the years ended December 31, 2013 and 2012 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, 2014 compared to year ended December 31, 2013

Operation and maintenance expenses decreased due primarily to lower vegetation management requirements of $1.4 million.

Year ended December 31, 2013 compared to year ended December 31, 2012

Operation and maintenance expenses decreased due to lower vegetation management requirements of $4.8 million, lower NERC compliance activities associated with surveying transmission overhead lines of $2.8 million and lower expenses associated with overhead line maintenance activities of $1.5 million.

General and administrative expenses

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.

Year ended December 31, 2013 compared to year ended December 31, 2012

General and administrative expenses increased by $23.7 million due to higher legal, advisory and financial services fees for the Entergy Transaction, $6.7 million due to higher compensation-related expenses primarily for personnel additions and $3.2 million due to an increase in other professional services such as legal, advisory and financial services fees.

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Depreciation and amortization expenses

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.

Year ended December 31, 2013 compared to year ended December 31, 2012

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, 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.

Year ended December 31, 2013 compared to year ended December 31, 2012

Taxes other than income taxes increased due to higher property tax expenses primarily due to our Regulated Operating Subsidiaries’ 2012 capital additions, which are included in the assessments for 2013 property taxes.

Other expenses (income)

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 during the period.

The loss on extinguishment of debt in 2014 related to the 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.

Year ended December 31, 2013 compared to year ended December 31, 2012

AFUDC equity increased due primarily to higher balances of construction work in progress eligible for AFUDC during the period.

Other income decreased and other expense increased primarily due to the gain recognized in other income for the investments held for the supplemental benefit plans in 2012 and the loss recognized in other expense for such investments in 2013. See further discussion in Note 11 to the consolidated financial statements.

Income Tax Provision

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 is 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.

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Year ended December 31, 2013 compared to year ended December 31, 2012

Our effective tax rates for the years ended December 31, 2013 and 2012 are 33.7% and 36.6%, 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 is 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 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 which 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 we expect to incur to fund our capital expenditures and for general corporate purposes.


•	Fund any potential share repurchases available under the Board of Directors authorized share repurchase program as described in Note 13 to the consolidated financial statements.

•

Fund contributions to our retirement benefit plans, as described in Note 11 to the consolidated financial statements. We expect to contribute up to $13.0 million to these plans in 2015. The impact of the growth in the number of participants in our retirement benefit plans and changes in the requirements of the Pension Protection Act may require contributions to our retirement benefit plans to be higher than we have experienced in the past.

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 to fund capital investments. ITC Holdings’ sources of cash are dividends and other payments received by us from our Regulated Operating Subsidiaries and any other subsidiaries we may have in addition to 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 revolving credit agreements and our cash and cash equivalents as needed to meet our short-term cash requirements. As described in Note 8 to the consolidated financial statements, we entered into new revolving credit agreements in March 2014 at ITC Holdings and its Regulated Operating Subsidiaries with total borrowing capacity of $1.0 billion, an increase of $275.0 million from the prior revolving

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credit agreements. As of December 31, 2014, we had consolidated indebtedness under our revolving and term loan credit agreements of $473.8 million, with unused capacity under the agreements of $687.2 million. See Note 8 to the consolidated financial statements for a detailed discussion of these agreements and borrowing and repayment activity during the years ended December 31, 2014 and 2013.

As of December 31, 2014, we had approximately $175.0 million of debt maturing within one year, which we expect to refinance with long-term debt. To address our long-term capital requirements and to 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 in the event we experience difficulties in accessing capital. We expect to be able to obtain such additional financing for both our short and long-term requirements 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
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 December 6, 2013, Standard and Poor’s Ratings Services (“Standard and Poor’s”) upgraded the senior unsecured credit rating of ITC Holdings and reaffirmed the secured credit ratings of ITCTransmission, METC and ITC Midwest. On October 7, 2014, Standard and Poor’s issued a secured credit rating for ITC Great Plains. All of the ratings have a stable outlook.


(b)	On April 15, 2014, Moody’s Investor Service, Inc. (“Moody’s”) reaffirmed the credit ratings for ITC Holdings and the MISO Regulated Operating Subsidiaries and on October 8, 2014, issued a secured credit rating for ITC Great Plains. All of the ratings have a stable outlook.

Covenants

Our debt instruments include senior notes, secured notes, first mortgage bonds and unsecured revolving and term loan credit agreements containing numerous financial and operating covenants that place significant restrictions, which are described in Note 8 to the consolidated financial statements. As of December 31, 2014, we were in compliance with all debt covenants. 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)	2014			2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	244,083		$	233,506		$	187,876
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	128,036			118,596			106,512
Recognition of and refund and collection of revenue accruals and deferrals — including accrued interest	(4,093		)	(11,972		)	(13,052		)
Deferred income tax expense	90,373			76,703			67,285
Tax benefit for excess tax deductions of share-based compensation	(7,767		)	(4,302		)	(23,022		)
Other	50,869			36,665			1,924
Net cash provided by operating activities	501,501			449,196			327,523
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(733,145		)	(821,588		)	(802,763		)
Other	(1,556		)	(4,700		)	(6,298		)
Net cash used in investing activities	(734,701		)	(826,288		)	(809,061		)
CASH FLOWS FROM FINANCING ACTIVITIES
Net issuance/repayment of long-term debt (including revolving and term loan credit agreements)	462,639			464,425			501,740
Issuance of common stock	20,713			10,042			14,189
Dividends on common stock	(95,595		)	(84,129		)	(75,153		)
Refundable deposits from and repayments to generators for transmission network upgrades — net	(22,850		)	(5,955		)	(4,943		)
Repurchase and retirement of common stock	(134,284		)	(4,885		)	(7,266		)
Tax benefit for excess tax deductions of share-based compensation	7,767			4,302			23,022
Other	(11,724		)	1,380			(2,208		)
Net cash provided by financing activities	226,666			385,180			449,381
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS	(6,534		)	8,088			(32,157		)
CASH AND CASH EQUIVALENTS — Beginning of period	34,275			26,187			58,344
CASH AND CASH EQUIVALENTS — End of period	$	27,741		$	34,275		$	26,187

Cash Flows From Operating Activities

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.

Year ended December 31, 2013 compared to year ended December 31, 2012

Net cash provided by operating activities increased $121.7 million in 2013 compared to 2012. The increase in cash provided by operating activities was due primarily to an increase in cash received from operating revenues of $81.6 million and the timing of tax payments, which resulted in lower income taxes paid of $21.1 million during 2013 compared to 2012. Additionally, there was a decrease of $18.7 million in the recognized reductions of federal and state income tax liabilities related to tax benefits for excess tax deductions of share-based compensation in 2013 as compared to 2012. These tax benefits are reflected as financing cash inflows.

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Cash Flows From Investing Activities

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.”

Year ended December 31, 2013 compared to year ended December 31, 2012

Net cash used in investing activities increased $17.2 million in 2013 compared to 2012. The increase in cash used in investing activities was due primarily to higher investments in property, plant and equipment during 2013 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, 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 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.

Year ended December 31, 2013 compared to year ended December 31, 2012

Net cash provided by financing activities decreased $64.2 million in 2013 compared to 2012. The decrease in cash provided by financing activities was due primarily to the payments of $452.0 million to retire long-term debt at ITC Holdings and ITCTransmission and the net decrease of $343.3 million in amounts outstanding under our revolving and term loan credit agreements during 2013 compared to 2012. Additionally, there was a decrease of $18.7 million in the recognized reductions of federal and state income tax liabilities related to tax benefits for excess tax deductions of share-based compensation in 2013 as compared to 2012. These decreases were partially offset by the proceeds of $933.0 million received from the issuance of long-term debt in 2013 as compared to the proceeds of $175.0 million received from the issuance of long-term debt in 2012.

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Contractual Obligations

The following table details our contractual obligations as of December 31, 2014:



			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	$	—	$	574,344	$	200,000	$	1,150,340
ITC Holdings revolving credit agreement	53,500		—		—		53,500		—
ITC Holdings term loan credit agreement	161,000		—		161,000		—		—
ITCTransmission First Mortgage Bonds	585,000		—		100,000		—		485,000
ITCTransmission revolving credit agreement	14,300		—		—		14,300		—
METC Senior Secured Notes	450,000		175,000		—		—		275,000
ITC Midwest First Mortgage Bonds	525,000		—		40,000		35,000		450,000
ITC Midwest revolving credit agreement	191,200		—		—		191,200		—
ITC Great Plains First Mortgage Bonds	150,000		—		—		—		150,000
ITC Great Plains revolving credit agreement	53,800		—		—		53,800		—
Interest payments:
ITC Holdings Senior Notes	1,105,033		98,991		253,189		118,221		634,632
ITCTransmission First Mortgage Bonds	630,487		29,326		70,857		38,613		491,691
METC Senior Secured Notes	356,545		21,566		36,270		24,180		274,529
ITC Midwest First Mortgage Bonds	464,525		27,196		78,667		48,630		310,032
ITC Great Plains First Mortgage Bonds	186,593		6,240		18,720		12,480		149,153
Operating leases	5,435		850		2,185		934		1,466
Purchase obligations	44,192		42,272		1,280		640		—
Regulatory liabilities — revenue deferrals, including accrued interest	73,883		39,972		33,911		—		—
METC Easement Agreement	359,721		10,041		30,123		20,082		299,475
Total obligations	$	7,334,898	$	451,454	$	1,400,546	$	811,580	$	4,671,318

Interest payments included above relate only to our fixed-rate long-term debt outstanding at December 31, 2014. 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 2014, we paid $8.7 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, 2014, 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, included 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.

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.

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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, to settle regulatory liabilities related to asset removal costs and liabilities to refund deposits from generators for transmission network upgrades 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

Our consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The preparation of these consolidated financial statements requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. The application of these policies necessarily involves 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 $229.1 million and $200.0 million, respectively, as of December 31, 2014. Future regulatory changes or changes in the competitive environment could result in discontinuing the application of the guidance for accounting 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 $48.8 million relating to intangible assets at December 31, 2014 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 a 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 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 requirements in the Accounting Standards Codification for accounting for rate-regulated utilities and the effects of certain alternative revenue programs. Accordingly,

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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. In accordance with the standards set forth by the FASB for goodwill, we are required to perform an impairment test annually or whenever events or circumstances indicate that the value of goodwill may be impaired. In order to perform these impairment tests, we determined fair value using quoted market prices in active markets, and valuation techniques based on discounted future cash flows under various scenarios. We also considered estimates of market-based valuation multiples for companies within our Regulated Operating Subsidiaries’ peer group. 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, 2014 and 2013, consolidated goodwill totaled $950.2 million. We completed our annual goodwill impairment test as of October 1, 2014 and determined that no impairment exists. There were no events subsequent to October 1, 2014 that indicated impairment of our goodwill. We do not believe there is a material risk of our goodwill being impaired in the near term at ITCTransmission, METC or ITC Midwest.

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 reserves for those matters where a loss is considered probable and reasonably estimable in accordance with GAAP. The adequacy of reserves 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 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, NERC, the Internal Revenue Service, or the Environmental Protection Agency.


•	Completion of certain milestones relating to development initiatives.

Share-Based Awards

Our accounting for share-based payments requires us to determine the fair value of awards of ITC Holdings’ common stock issued in the form of restricted stock and stock option awards. We use the value of ITC Holdings’ common stock at the date of the grant in the calculation of the fair value of our share-based awards. The restricted stock awards are recorded at fair value at the date of the grant. The fair value of stock options held by our employees is determined using a Black-Scholes option valuation method, which is a valuation technique that is acceptable for share-based payment accounting. Key assumptions in determining fair value include volatility, risk-free interest rate, dividend yield and expected term. In the event different assumptions were used, a different fair value would be derived that could cause the related expense to be materially higher or lower. We amortize the fair value of the awards on a straight-line basis (net of any estimated forfeitures) over the vesting period of the awards.

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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, was $3,985.6 million at December 31, 2014. The total book value of our consolidated long-term debt and debt maturing within one year, excluding revolving and term loan credit agreements, was $3,629.8 million at December 31, 2014. 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, at December 31, 2014. An increase in interest rates of 10% (from 7.0% to 7.7%, for example) at December 31, 2014 would decrease the fair value of debt by $176.1 million, and a decrease in interest rates of 10% at December 31, 2014 would increase the fair value of debt by $189.6 million at that date.

Revolving and Term Loan Credit Agreements

At December 31, 2014, we had a consolidated total of $473.8 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, 2014 would increase or decrease the total interest expense by $0.6 million, respectively, for an annual period on a constant borrowing level of $473.8 million.

Derivative Instruments and Hedging Activities

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financial instruments for trading or speculative purposes. In May 2014, we executed, settled and terminated $150.0 million of 10-year interest rate swaps in conjunction with the Senior Notes issued at ITC Holdings as described in Note 8 to the consolidated financial statements. As of December 31, 2014, we held 10-year interest rate swaps with a notional amount of $50.0 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 (“5.875% Senior Notes”). ITC Holdings entered into an additional 10-year interest rate swap on January 14, 2015 with a notional amount of $25.0 million, which also manages 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 22.2%, 24.2% and 29.0%, respectively, or $224.5 million, $244.7 million and $292.9 million, respectively, of our consolidated billed revenues for 2014. These percentages of total billed revenues of DTE Electric, Consumers Energy and IP&L include the collection of 2012 revenue accruals and deferrals and exclude any amounts for the 2014 revenue accruals and deferrals that were included in our 2014 operating revenues, but will not be billed to our customers until 2016. 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		49
Report of Independent Registered Public Accounting Firm		50
Report of Independent Registered Public Accounting Firm		51
Consolidated Statements of Financial Position as of December 31, 2014 and 2013		52
Consolidated Statements of Operations for the Years Ended December 31, 2014, 2013 and 2012		53
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2014, 2013 and 2012		54
Consolidated Statements of Changes in Stockholders’ Equity for the Years Ended December 31, 2014, 2013 and 2012		55
Consolidated Statements of Cash Flows for the Years Ended December 31, 2014, 2013 and 2012		56
Notes to Consolidated Financial Statements		57
Schedule I - Condensed Financial Information of Registrant		100

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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, 2014.

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, 2014. 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, 2014 and 2013, 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, 2014. 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, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, 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, 2014, 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 26, 2015 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Detroit, Michigan

February 26, 2015

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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, 2014, 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, 2014, 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, 2014 of the Company and our report dated February 26, 2015 expressed an unqualified opinion on those financial statements and financial statement schedule.

/s/ DELOITTE & TOUCHE LLP

Detroit, Michigan

February 26, 2015

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ITC HOLDINGS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION



	December 31,
(In thousands, except share data)	2014		2013
ASSETS
Current assets
Cash and cash equivalents	$	27,741	$	34,275
Accounts receivable	100,998		89,348
Inventory	30,892		31,986
Deferred income taxes	14,511		17,225
Regulatory assets	5,393		6,334
Prepaid and other current assets	7,281		12,370
Total current assets	186,816		191,538
Property, plant and equipment (net of accumulated depreciation and amortization of $1,388,217 and $1,330,094, respectively)	5,496,875		4,846,526
Other assets
Goodwill	950,163		950,163
Intangible assets (net of accumulated amortization of $24,917 and $21,616, respectively)	48,794		49,328
Regulatory assets	223,712		182,105
Deferred financing fees (net of accumulated amortization of $15,972 and $15,261, respectively)	30,311		25,585
Other	37,418		36,998
Total other assets	1,290,398		1,244,179
TOTAL ASSETS	$	6,974,089	$	6,282,243
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	107,969	$	111,145
Accrued payroll	23,502		21,930
Accrued interest	50,538		53,049
Accrued taxes	41,614		29,805
Regulatory liabilities	39,972		46,187
Refundable deposits from generators for transmission network upgrades	10,376		23,283
Debt maturing within one year	175,000		200,000
Other	14,043		13,980
Total current liabilities	463,014		499,379
Accrued pension and postretirement liabilities	69,562		53,704
Deferred income taxes	656,562		562,938
Regulatory liabilities	160,070		106,986
Refundable deposits from generators for transmission network upgrades	9,384		19,328
Other	17,354		14,064
Long-term debt	3,928,586		3,412,112
Commitments and contingent liabilities (Notes 4 and 16)
STOCKHOLDERS’ EQUITY
Common stock, without par value, 300,000,000 shares authorized, 155,140,967 and 157,500,795 shares issued and outstanding at December 31, 2014 and 2013, respectively	923,191		1,014,435
Retained earnings	741,550		592,970
Accumulated other comprehensive income	4,816		6,327
Total stockholders’ equity	1,669,557		1,613,732
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	6,974,089	$	6,282,243

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)	2014			2013			2012
OPERATING REVENUES	$	1,023,048		$	941,272		$	830,535
OPERATING EXPENSES
Operation and maintenance	111,623			112,821			121,941
General and administrative	115,031			149,109			112,091
Depreciation and amortization	128,036			118,596			106,512
Taxes other than income taxes	76,534			65,824			59,701
Other operating income and expense — net	(1,005		)	(1,139		)	(769		)
Total operating expenses	430,219			445,211			399,476
OPERATING INCOME	592,829			496,061			431,059
OTHER EXPENSES (INCOME)
Interest expense — net	186,636			168,319			155,734
Allowance for equity funds used during construction	(20,825		)	(30,159		)	(23,000		)
Loss on extinguishment of debt	29,205			—			—
Other income	(1,103		)	(1,038		)	(2,401		)
Other expense	4,511			6,571			4,218
Total other expenses (income)	198,424			143,693			134,551
INCOME BEFORE INCOME TAXES	394,405			352,368			296,508
INCOME TAX PROVISION	150,322			118,862			108,632
NET INCOME	$	244,083		$	233,506		$	187,876

Basic earnings per common share	$	1.56		$	1.49		$	1.22
Diluted earnings per common share	$	1.54		$	1.47		$	1.20
Dividends declared per common share	$	0.610		$	0.535		$	0.487

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)	2014			2013		2012
NET INCOME	$	244,083		$	233,506	$	187,876
OTHER COMPREHENSIVE (LOSS) INCOME
Derivative instruments, net of tax (Note 13)	(1,479		)	24,304		(2,680		)
Available-for-sale securities, net of tax (Note 13)	(32		)	71		—
TOTAL OTHER COMPREHENSIVE (LOSS) INCOME, NET OF TAX	(1,511		)	24,375		(2,680		)
TOTAL COMPREHENSIVE INCOME	$	242,572		$	257,881	$	185,196

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, 2011	153,970,104		$	943,444		$	330,816		$	(15,368	)	$	1,258,892
Net income	—		—			187,876			—			187,876
Repurchase and retirement of common stock	(298,599	)	(7,266		)	—			—			(7,266		)
Dividends declared on common stock ($0.487 per share)	—		—			(75,153		)	—			(75,153		)
Stock option exercises	2,555,160		12,593			—			—			12,593
Shares issued under the Employee Stock Purchase Plan	76,563		1,596			—			—			1,596
Issuance of restricted stock	475,797		—			—			—			—
Forfeiture of restricted stock	(33,483	)	—			30			—			30
Share-based compensation, net of forfeitures	—		15,592			—			—			15,592
Tax benefit for excess tax deductions of share-based compensation	—		23,022			—			—			23,022
Other comprehensive loss, net of tax (Note 13)	—		—			—			(2,680		)	(2,680		)
Other	—		353			—			—			353
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

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)	2014			2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	244,083		$	233,506		$	187,876
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	128,036			118,596			106,512
Recognition of and refund and collection of revenue accruals and deferrals — including accrued interest	(4,093		)	(11,972		)	(13,052		)
Deferred income tax expense	90,373			76,703			67,285
Allowance for equity funds used during construction	(20,825		)	(30,159		)	(23,000		)
Loss on extinguishment of debt	29,205			—			—
Other	17,697			17,864			13,772
Changes in assets and liabilities, exclusive of changes shown separately:
Accounts receivable	(11,869		)	(16,312		)	1,721
Inventory	1,094			5,371			(2,502		)
Prepaid and other current assets	5,089			16,891			(25,102		)
Accounts payable	(19,061		)	17,638			(5,400		)
Accrued payroll	525			1,619			1,583
Accrued interest	(2,511		)	8,341			1,066
Accrued taxes	19,756			6,113			24,247
Tax benefit on the excess tax deduction of share-based compensation	(7,767		)	(4,302		)	(23,022		)
Other current liabilities	(2,314		)	1,630			2,912
Other non-current assets and liabilities, net	34,083			7,669			12,627
Net cash provided by operating activities	501,501			449,196			327,523
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(733,145		)	(821,588		)	(802,763		)
Proceeds from sale of marketable securities	495			20,844			5,935
Purchases of marketable securities	(6,091		)	(22,250		)	(11,779		)
Other	4,040			(3,294		)	(454		)
Net cash used in investing activities	(734,701		)	(826,288		)	(809,061		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	798,664			933,025			175,000
Borrowings under revolving credit agreements	1,660,000			1,090,100			1,355,150
Borrowings under term loan credit agreements	110,000			675,000			200,000
Retirement of long-term debt - including extinguishment of debt costs	(298,625		)	(452,000		)	—
Repayments of revolving credit agreements	(1,618,400		)	(1,146,700		)	(1,228,410		)
Repayments of term loan credit agreements	(189,000		)	(635,000		)	—
Issuance of common stock	20,713			10,042			14,189
Dividends on common and restricted stock	(95,595		)	(84,129		)	(75,153		)
Refundable deposits from generators for transmission network upgrades	5,833			32,281			33,310
Repayment of refundable deposits from generators for transmission network upgrades	(28,683		)	(38,236		)	(38,253		)
Repurchase and retirement of common stock	(134,284		)	(4,885		)	(7,266		)
Tax benefit on the excess tax deduction of share-based compensation	7,767			4,302			23,022
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	(11,724		)	1,380			(2,208		)
Net cash provided by financing activities	226,666			385,180			449,381
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS	(6,534		)	8,088			(32,157		)
CASH AND CASH EQUIVALENTS — Beginning of period	34,275			26,187			58,344
CASH AND CASH EQUIVALENTS — End of period	$	27,741		$	34,275		$	26,187

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, to reduce transmission constraints and to 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 to 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 and 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, 2014, 2013 and 2012:



	Year Ended December 31,
(In thousands)	2014		2013		2012
Supplementary cash flows information:
Interest paid (net of interest capitalized)	$	185,288	$	155,112	$	148,598
Income taxes paid — net	44,524		20,092		41,174
Supplementary non-cash investing and financing activities:
Additions to property, plant and equipment and other long-lived assets (a)	$	90,949	$	68,276	$	94,218
Allowance for equity funds used during construction	20,825		30,159		23,000

____________________________


(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, 2014, 2013 or 2012, 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, 2014 and 2013, 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 $118.9 million, $109.4 million and $97.3 million for 2014, 2013 and 2012, 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%, 2.2% and 2.4% for 2014, 2013 and 2012, 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 $5.1 million, $8.0 million and $7.0 million for 2014, 2013 and 2012, respectively, was a reduction to interest expense. 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 assets disposed of 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 we make 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 needed 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 $19.7 million, $2.6 million and $11.3 million were recorded as reductions to property, plant and equipment during the years ended December 31, 2014, 2013 or 2012, 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 which 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 investment loss in earnings.

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, an impairment loss is recognized resulting in the asset being written down to its estimated fair value.

Goodwill and Intangible Assets — We comply with the standards set forth by the FASB for goodwill and other intangible assets. Under these standards, goodwill and other intangibles with indefinite lives are not subject to amortization. However, goodwill and other intangibles with indefinite lives are subject to fair value-based rules for measuring impairment, and resulting write-downs, if any, are to be reflected in operating expense. In order to perform these impairment tests, we determined fair value using valuation techniques based on discounted future cash flows under various scenarios and we also considered estimates of market-based valuation multiples for companies within the peer group of the reporting unit that has goodwill recorded. These accounting standards require that goodwill be reviewed at least annually for impairment and whenever facts or circumstances indicate that the value of goodwill may be impaired. We have goodwill recorded relating to the acquisitions of each our MISO Regulated Operating Subsidiaries. We completed our annual goodwill impairment test for each of our MISO Regulated Operating Subsidiaries as of October 1, 2014 and determined that no impairment exists. There were no events subsequent to October 1, 2014 that indicated impairment of our goodwill. We do not believe there is a material risk of our goodwill being impaired in the near term at ITCTransmission, METC or ITC Midwest. Our intangible assets have finite lives and are amortized over their useful lives, refer to Note 6.

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 are 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 to interest expense the amortization of deferred financing fees

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and the amortization of our debt discounts for 2014, 2013 and 2012 of $4.1 million, $4.1 million and $4.0 million, 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 refers to 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 or incur a gain or loss. The standards for asset retirement obligations applied to our Regulated Operating Subsidiaries require us to recognize regulatory assets or liabilities for the timing differences between when we recover legal asset retirement obligations in rates and when we would recognize these costs under the standards. There have not been any significant changes to our asset retirement obligations in 2014. Our asset retirement obligations as of December 31, 2014 and 2013 of $5.9 million and $5.7 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 reserves for those matters where a loss is considered probable and reasonably estimable in accordance with GAAP. The adequacy of reserves 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. The 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 an Amended and Restated 2003 Stock Purchase and Option Plan for Key Employees of ITC Holdings Corp. and its subsidiaries (“2003 Plan”) and a Second Amended and Restated 2006 Long-Term Incentive Plan (“LTIP”) pursuant to which we grant various share-based awards, including options and restricted stock. Compensation expense is recorded for restricted stock awards that are expected to vest based on their fair value at grant date, and is amortized over the expected vesting period. We recognize expense for stock options that are expected to vest based on their fair value at grant date 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. The grant date is the date at which our commitment to issue share based awards to the employee or a director arises, which is generally the later of the board approval date, the date of hire of the employee or the date of the employee’s compensation agreement which contains the commitment to issue the award.

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We also have an Employee Stock Purchase Plan (“ESPP”) which is a compensatory plan. Compensation expense 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 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.

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 2010 and earlier. State and city jurisdictions that remain subject to examination range from tax years 2010 to 2013. In the event we are assessed interest or penalties by any income tax jurisdictions, interest would be recorded as interest expense and penalties would be recorded as other expense.

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, 2016 and may be adopted using a full or modified retrospective application. We do not expect the guidance to have a material impact on our 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 U.S. 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 disclosure.

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. On March 20, 2014, 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 on May 19, 2014. On January 22, 2015, the FERC conditionally accepted the May 19,

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2014 compliance filing, subject to a further compliance filing. We do not expect the revised formula rate protocols to impact our results of operations, cash flows or financial condition.

Complaint of IP&L

In 2012, IP&L filed a complaint with the FERC against ITC Midwest’s policy for reimbursement of certain network upgrades under Section 206 of the FPA. The complaint challenged ITC Midwest’s FERC-approved reimbursement policy for up to 100% reimbursement of the costs funded upfront by qualifying generators for network upgrades.

In July 2013, FERC issued an order indicating that the use of Attachment FF was no longer just and reasonable for generator interconnections on the ITC Midwest system and required MISO, on behalf of ITC Midwest, to prospectively revise ITC Midwest’s Attachment FF of the MISO Tariff to conform ITC Midwest’s policy to the default generator interconnection cost recovery provisions used in most other MISO pricing zones. The order does not modify agreements executed or filed unexecuted prior to July 18, 2013. In August 2013, MISO made the required compliance filing to revise ITC Midwest’s Attachment FF of the MISO Tariff and ITC Midwest filed for rehearing of this matter with FERC. On February 20, 2014, FERC issued an order which accepted the required revisions to ITC Midwest’s Attachment FF for the MISO Tariff, making them effective as of July 18, 2013 but denied ITC Midwest’s request for rehearing.

Under the default MISO cost recovery provisions in effect for new generator interconnection agreements (“GIAs”) on MISO’s system, ITC Midwest intends to utilize the option that exists to elect to fund network upgrades and recover such costs from the interconnection customer. We do not expect the revised policy to have a material impact on our results of operations, cash flows or financial condition.

FERC Audit Refund

See “FERC Audit of ITC Midwest” in Note 16 for a discussion of the FERC audit refund.

Rate of Return on Equity and Capital Structure Complaint

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

Cost-Based Formula Rates with True-Up Mechanism

The transmission rates at our Regulated Operating Subsidiaries are set annually, using the FERC-approved formula rates, and the rates 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 adjust their transmission rates 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 FERC-approved formula rates do not require further action or FERC filings for the calculated joint zone rates to go into effect, although the rates are subject to legal challenge at the FERC. Our Regulated Operating Subsidiaries will continue to use formula rates to calculate their respective annual revenue requirements unless the FERC determines the rates to be unjust and unreasonable or another mechanism is determined by the FERC to be just and reasonable.

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 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 customer bills within two years under the provisions of the formula rate templates.

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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, 2014:



(In thousands)	Total
Balance as of December 31, 2013	$	(60,196	)
Net refund of 2012 revenue deferrals and accruals, including accrued interest	27,260
Net revenue deferral for the year ended December 31, 2014	(21,045		)
Net accrued interest payable for the year ended December 31, 2014	(2,122		)
Balance as of December 31, 2014	$	(56,103	)

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



(In thousands)	Total
Current assets	$	5,393
Non-current assets	12,387
Current liabilities	(39,972		)
Non-current liabilities	(33,911		)
Balance as of December 31, 2014	$	(56,103	)

ITC Great Plains Start-up, Development and Pre-construction Regulatory Assets

As of December 31, 2014, we have recorded a total of $14.1 million of regulatory assets for start-up, development and pre-construction expenses, including associated interest carrying charges, incurred by ITC Great Plains, which include certain costs incurred for the KETA Project and the Kansas V-Plan Project prior to construction. ITC Great Plains made a filing with the FERC under Section 205 of the FPA in May 2013 to recover these start-up, development and pre-construction expenses, including associated carrying charges, in future rates. If FERC authorization is received, ITC Great Plains will include the unamortized balance of the regulatory assets in its rate base and will amortize them over a 10-year period beginning at the later of the project in-service date or the FERC authorization date. The amortization expense will be recovered through ITC Great Plains’ cost-based formula rate template beginning in the period in which amortization begins.

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 as a reduction 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, 2014 and 2013:



(In thousands)	2014		2013
Regulatory Assets:
Current:
Revenue accruals (including accrued interest of $120 and $114 as of December 31, 2014 and 2013, respectively)	$	5,393	$	6,334
Non-current:
Revenue accruals (including accrued interest of $75 and $27 as of December 31, 2014 and 2013, respectively)	12,387		3,037
ITCTransmission ADIT Deferral (net of accumulated amortization of $35,856 and $32,826 as of December 31, 2014 and 2013, respectively)	24,746		27,776
METC ADIT Deferral (net of accumulated amortization of $18,869 and $16,511 as of December 31, 2014 and 2013, respectively)	23,587		25,945
METC Regulatory Deferrals (net of accumulated amortization of $6,172 and $5,400 as of December 31, 2014 and 2013, respectively)	9,257		10,029
Income taxes recoverable related to AFUDC equity	87,168		75,798
ITC Great Plains start-up, development and pre-construction	14,054		13,916
Pensions and postretirement	34,151		15,079
Income taxes recoverable related to implementation of the Michigan Corporate Income Tax	8,869		8,869
Accrued asset removal costs	7,337		170
Other	2,156		1,486
Total non-current	223,712		182,105

Total	$	229,105	$	188,439

Revenue Accruals

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 the revenue accruals, but do accrue interest carrying costs which are subject to rate recovery along with the principal amount of the revenue accrual.

ITCTransmission ADIT Deferral

The carrying amount of the ITCTransmission 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 the ITCTransmission ADIT Deferral 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 2014, 2013 and 2012, 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 the regulatory asset for METC ADIT Deferral 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 the regulatory asset for METC ADIT Deferral that is included in rate base. METC recorded amortization expense of $2.4 million annually during 2014, 2013 and 2012, 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 MTH acquired METC from Consumers Energy (the “METC Regulatory Deferrals”). The original amount recorded for the regulatory asset for METC Regulatory Deferrals 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 the METC Regulatory Deferrals that is included in rate base. METC recorded amortization expense of $0.8 million annually during 2014, 2013 and 2012, 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. We do not earn a return on this regulatory asset and the related deferred tax liabilities do not reduce rate base.

ITC Great Plains Start-up, Development and Pre-Construction

The start-up, development and pre-construction regulatory assets consists of certain costs incurred by ITC Great Plains from inception through the effective date of the ITC Great Plains’ cost-based formula rate, including costs which had been incurred to develop and acquire transmission assets in the SPP region and certain costs incurred for the KETA Project and Kansas V-Plan Project prior to construction. These costs relate primarily to obtaining various state, SPP and FERC approvals necessary for ITC Great Plains to own transmission assets and build new facilities in the SPP region, efforts to establish the ITC Great Plains’ cost-based formula rate, the establishment of ITC Great Plains as a public utility in Kansas and Oklahoma, obtaining the necessary approvals and authorizations for the state regulators in Kansas and Oklahoma, as well as engineering studies, routing studies and education and outreach to stakeholders on ITC Great Plains’ efforts to bring these projects to the SPP region, and other costs incurred specific to the KETA and V-Plan Projects prior to construction.

The start-up, development and pre-construction regulatory assets accrue carrying charges 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. The carrying charges began to accrue in March 2009 and will continue until such time that the regulatory assets are included in rate base. The equity component of these carrying charges including applicable taxes, totaling $10.5 million as of December 31, 2014, 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. ITC Great Plains made a filing with the FERC under Section 205 of the FPA in May 2013 to recover these start-up, development and pre-construction expenses, including associated carrying charges, in future rates. If FERC authorization is received, ITC Great Plains will include the unamortized balance of the start-up, development and pre-construction regulatory assets in its rate base and will amortize them over a 10-year period beginning at the later of the project in-service date or the FERC authorization date. The amortization expense will be recovered through ITC Great Plains’ cost-based formula rate template beginning in the period in which amortization begins.

Pensions and Postretirement

Accounting standards for defined benefit pension and other postretirement plans for rate-regulated entities allow that amounts that otherwise would have been charged and or credited to accumulated other comprehensive income are 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 the pension and postretirement 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 that is attributed 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 which allowed for deductions and credits for certain activities, none of which are part of the CIT. The change in Michigan tax law required us to

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remove deferred income tax balances recognized under the MBT and establish new deferred income tax balances under the CIT in 2011, and the net result was incremental deferred state income tax liabilities at both ITCTransmission and METC. Under our cost-based formula rates with true-up mechanism, the future taxes receivable as a result of the tax law change is expected to be collected from customers through future rates and has resulted in the recognition of a regulatory asset. ITCTransmission and METC do not earn a return on the balance of the CIT 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 costs incurred to remove property, plant and equipment and the estimated removal costs that have been recovered 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 differences between when legal asset retirement obligations are settled and when such obligations are recognized under the standards set forth by the FASB. Our Regulated Operating Subsidiaries include this item, excluding the cost component related to the recognition of our legal asset retirement obligations under the standards set forth by the FASB, as a reduction to accumulated depreciation for rate-making purposes, which is an increase to rate base.

Regulatory Liabilities

The following table summarizes the regulatory liability balances at December 31, 2014 and 2013:



(In thousands)	2014		2013
Regulatory Liabilities:
Current:
Revenue deferrals (including accrued interest of $1,853 and $1,535 as of December 31, 2014 and 2013, respectively) (a)	$	39,972	$	33,120
FERC audit refund (including accrued interest of $2,095 as of December 31, 2013) (b)	—		13,067
Total current	39,972		46,187
Non-current:
Revenue deferrals (including accrued interest of $541 and $581 as of December 31, 2014 and 2013, respectively) (a)	33,911		36,447
Accrued asset removal costs	70,705		67,571
Estimated potential refund related to return on equity complaint (including accrued interest of $870 as of December 31, 2014) (c)	47,780		—
Excess state income tax deductions	7,504		2,968
Other	170		—
Total non-current	160,070		106,986

Total	$	200,042	$	153,173

____________________________


(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 FERC audit refund in Note 16 under “FERC Audit of ITC Midwest.”


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

Accrued Asset Removal Costs

The carrying amount of the accrued asset removal costs represents the difference between incurred costs to remove property, plant and equipment and the estimated removal costs included in rates. The portion of depreciation expense included in our depreciation rates related to asset removal costs is added to this regulatory liability and removal expenditures incurred are charged to this regulatory liability. Our Regulated Operating Subsidiaries include this item within accumulated depreciation for rate-making purposes, which is a reduction to rate base.

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Excess State Income Tax Deductions

We have taken income tax deductions 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, 2014 and 2013, 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 acquisition, the METC acquisition and ITC Midwest’s asset acquisition, respectively.

Intangible Assets

Pursuant to the METC acquisition in October 2006, we have identified intangible assets with finite lives derived from the portion of regulatory assets recorded on METC’s historical FERC financial statements that were not recorded on METC’s historical GAAP financial statements associated with the METC Regulatory Deferrals and the METC ADIT Deferral. The carrying amount of the intangible asset for METC Regulatory Deferrals at December 31, 2014 and 2013 is $23.7 million and $25.7 million, respectively, and is amortized over 20 years beginning January 1, 2007. The carrying amount of the intangible asset for METC ADIT Deferral at December 31, 2014 and 2013 is $10.5 million and $11.5 million, respectively, and is amortized over 18 years beginning January 1, 2007, which also corresponds to the amortization period established in the METC rate case settlement. METC earns an equity return on the remaining unamortized balance of both the intangible asset for METC Regulatory Deferrals and the intangible asset for METC ADIT Deferral and recovers the amortization expense through METC’s cost-based formula rate template.

ITC Great Plains has recorded intangible assets for payments and obligations made by ITC Great Plains to certain transmission owners 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 $14.6 million and $12.1 million (net of accumulated amortization of $0.7 million and $0.4 million, respectively) as of December 31, 2014 and 2013, respectively. The amortization period for these intangible assets is 50 years.

During each of the years ended December 31, 2014, 2013 and 2012, we recognized $3.3 million, $3.2 million and $3.1 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, 2014 to be as follows:



(In thousands)
2015	$	3,331
2016	3,331
2017	3,331
2018	3,331
2019	3,331
2020 and thereafter	32,139
Total	$	48,794

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7. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment — net consisted of the following at December 31, 2014 and 2013:



(In thousands)	2014			2013
Property, plant and equipment
Regulated Operating Subsidiaries:
Property, plant and equipment in service	$	6,396,449		$	5,641,240
Construction work in progress	391,788			423,433
Capital equipment inventory	68,170			75,470
Other	13,151			22,460
ITC Holdings and other	15,534			14,017
Total	6,885,092			6,176,620
Less: Accumulated depreciation and amortization	(1,388,217		)	(1,330,094		)
Property, plant and equipment — net	$	5,496,875		$	4,846,526

Additions to property, plant and equipment in service and construction work in progress during 2014 and 2013 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, 2014 and 2013:



(Amounts in thousands)	2014		2013
ITC Holdings 6.04% Senior Notes, Series A, due September 20, 2014 (a)	$	—	$	50,000
ITC Holdings 5.875% Senior Notes due September 30, 2016 (net of discount of $6 and $9, respectively) (b)	139,338		254,991
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 $166 and $174, respectively) (b)	200,174		254,826
ITC Holdings 6.05% Senior Notes due January 31, 2018 (net of discount of $487 and $644, respectively)	384,513		384,356
ITC Holdings 5.50% Senior Notes due January 15, 2020 (net of discount of $654 and $787, respectively)	199,346		199,213
ITC Holdings 4.05% Senior Notes due July 1, 2023 (net of discount of $606 and $677, respectively)	249,394		249,323
ITC Holdings 3.65% Senior Notes due June 15, 2024 (net of discount of $1,258)	398,742		—
ITC Holdings 5.30% Senior Notes due July 1, 2043 (net of discount of $763 and $791, respectively)	299,237		299,209
ITC Holdings Term Loan Credit Agreement due September 30, 2016	161,000		140,000
ITC Holdings Revolving Credit Agreement due May 17, 2016 (c)	—		—
ITC Holdings Revolving Credit Agreement due March 28, 2019	53,500		—
ITCTransmission 6.125% First Mortgage Bonds, Series C, due March 31, 2036 (net of discount of $79 and $82, respectively)	99,921		99,918
ITCTransmission 5.75% First Mortgage Bonds, Series D, due April 1, 2018 (net of discount of $37 and $49, respectively)	99,963		99,951
ITCTransmission 4.625% First Mortgage Bonds, Series E, due August 15, 2043 (net of discount of $437 and $452, respectively)	284,563		284,548
ITCTransmission 4.27% First Mortgage Bonds, Series F, due June 10, 2044	100,000		—
ITCTransmission Revolving Credit Agreement due May 17, 2016 (c)	—		41,100
ITCTransmission Revolving Credit Agreement due March 28, 2019	14,300		—
METC 5.75% Senior Secured Notes due December 10, 2015 (a)	175,000		175,000
METC 6.63% Senior Secured Notes due December 18, 2014 (a)	—		50,000
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		—
METC Revolving Credit Agreement due May 17, 2016 (c)	—		67,200
METC Revolving Credit Agreement due March 28, 2019	—		—
ITC Midwest 6.15% First Mortgage Bonds, Series A, due January 31, 2038 (net of discount of $405 and $423, respectively)	174,595		174,577
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 Revolving Credit Agreement due May 31, 2017 (c)	—		111,000
ITC Midwest Revolving Credit Agreement due March 28, 2019	191,200		—
ITC Great Plains 4.16% First Mortgage Bonds, Series A, due November 26, 2044	150,000		—
ITC Great Plains Term Loan Credit Agreement due November 28, 2014 (a)	—		100,000
ITC Great Plains Revolving Credit Agreement due February 16, 2015 (c)	—		51,900
ITC Great Plains Revolving Credit Agreement due March 28, 2019	53,800		—
Total debt	$	4,103,586	$	3,612,112

____________________________


(a)	As of December 31, 2014 and 2013, there was $175.0 million and $200.0 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.


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


(c)	The debt obligations were retired prior to maturity date.

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The annual maturities of debt as of December 31, 2014 are as follows:



(In thousands)
2015	$	175,000
2016	300,344
2017	90,000
2018	485,000
2019	312,800
2020 and thereafter	2,745,340
Total	$	4,108,484

ITC Holdings

Term Loan Credit Agreements

On December 20, 2013, ITC Holdings entered into an unsecured, unguaranteed term loan credit agreement, due September 30, 2016, with an initial borrowing capacity of $200.0 million, which was borrowed in full as of March 31, 2014. As of December 31, 2014 and 2013, ITC Holdings had $161.0 million and $140.0 million outstanding under this agreement, respectively. The term loan bears interest at a variable rate, subject to adjustment based on ITC Holdings’ credit rating. The proceeds were used for general corporate purposes, including the repayment of borrowings under the ITC Holdings’ revolving credit agreement. The weighted-average interest rate on the borrowing outstanding under this agreement was 1.3% at December 31, 2014.

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 July 3, 2013, ITC Holdings issued $250.0 million aggregate principal amount of its 4.05% Senior Notes, due July 1, 2023 and $300.0 million aggregate principal amount of its 5.30% Senior Notes, due July 1, 2043. The proceeds from these issuances were used to repay its $267.0 million of 5.25% Senior Notes due July 15, 2013, amounts borrowed under ITC Holdings’ various term loan credit agreements and for general corporate purposes.

On June 4, 2014, ITC Holdings issued $400.0 million aggregate principal amount of its 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 August 14, 2013, ITCTransmission issued $285.0 million aggregate principal amount of 4.625% First Mortgage Bonds, Series E, due August 15, 2043. The proceeds from the issuance were used to repay its term loan credit agreement of $185.0 million and $100.0 million outstanding under an intercompany advance agreement between ITCTransmission and ITC Holdings.

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.

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METC

Term Loan Credit Agreement

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 4, 2013, ITC Midwest issued $100.0 million aggregate principal amount of 4.09% First Mortgage Bonds, Series F, due April 30, 2043. The proceeds from the issuance were used to refinance existing indebtedness, partially fund capital expenditures and for general corporate purposes. 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

Term Loan Credit Agreement

On May 30, 2013, ITC Great Plains entered into an unsecured, unguaranteed term loan credit agreement due November 28, 2014, under which ITC Great Plains had borrowed the maximum $100.0 million as of December 31, 2013. The proceeds were used to refinance existing indebtedness, fund capital expenditures and for general corporate purposes. This borrowing was repaid in full in the fourth quarter of 2014.

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 the ITC Great Plains’ term loan credit agreement described above 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

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. The interest rate swaps listed below manage interest rate risk associated with the forecasted future issuance of fixed-rate debt related to the expected refinancing of the maturing ITC Holdings 5.875% Senior Notes, due September 30, 2016. As of December 31, 2014, ITC Holdings had $139.3 million outstanding under the 5.875% Senior Notes subsequent to the cash tender offer described above.



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
Total	$	50.0

The 10-year term interest rate swaps call for ITC Holdings to receive interest quarterly at a variable rate equal to LIBOR and to pay interest semi-annually at various fixed rates effective for the 10-year period beginning

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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 attributable to changes in benchmark interest rates from the trade date of the interest rate swaps to the issuance date of the debt obligation. On January 14, 2015, ITC Holdings entered into an additional interest rate swap contract with terms comparable to the interest rate swaps described above, consisting of an additional $25.0 million notional amount of a 10-year term interest rate swap with a fixed rate of 2.301%.

As of December 31, 2014, 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 forecasted debt. As of December 31, 2014, the fair value of the derivative instruments was a liability of $1.9 million recorded to other non-current liabilities. None of the interest rate swaps contain credit-risk-related contingent features. Refer to Note 12 for additional fair value information.

In May 2014, we executed, settled and terminated $150.0 million of 10-year interest rate swaps in conjunction with the Senior Notes issued at ITC Holdings described above. A summary of the terminated interest rate swaps is provided below:



Interest Rate Swaps	Amount		Weighted Average Fixed Rate of Interest Rate Swaps	Comparable Reference Rate of Senior Notes	Loss on Derivative		Settlement Date
(Amounts in millions)
10-year interest rate swaps	$	150.0	2.65%	2.53%	$	1.6	May 2014

The interest rate swaps qualified for hedge accounting treatment and the loss of $1.6 million was recognized as of December 31, 2014 for the effective portion of the hedges and recorded net of tax in AOCI. This amount is being amortized as a component of interest expense over the life of the related debt.

Revolving Credit Agreements

On March 28, 2014, ITC Holdings and its Regulated Operating Subsidiaries entered into new unsecured, unguaranteed revolving credit agreements maturing in March 2019, which replaced their existing revolving credit agreements. At December 31, 2014, 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)
Revolving Credit Agreements:
ITC Holdings	$	400.0	$	53.5	$	346.5	1.4%	(c)	0.175	%
ITCTransmission	100.0		14.3		85.7		1.1%	(d)	0.10	%
METC	100.0		—		100.0		n/a	(d)	0.10	%
ITC Midwest	250.0		191.2		58.8		1.1%	(d)	0.10	%
ITC Great Plains	150.0		53.8		96.2		1.1%	(d)	0.10	%
Total	$	1,000.0	$	312.8	$	687.2

____________________________


(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)	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.

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(d)	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, 2014, we were not in violation of any debt covenant.

9. EARNINGS PER SHARE

We report both basic and diluted earnings per share. Our restricted stock and deferred stock units contain rights to receive nonforfeitable dividends and thus, are participating securities requiring the two-class method of computing earnings per share.

A reconciliation of both calculations for the years ended December 31, 2014, 2013 and 2012 is presented in the following table (see additional information below under “Stock Split” for the recast share and per share data for the years ended December 31, 2013 and 2012 as a result of the three-for-one stock split):



	Year Ended December 31,
(In thousands, except share, per share data and percentages)	2014			2013			2012
Numerator:
Net income	$	244,083		$	233,506		$	187,876
Less: dividends declared and paid — common and restricted shares	(95,503		)	(84,104		)	(75,124		)
Undistributed earnings	148,580			149,402			112,752
Percentage allocated to common shares (a)	99.2		%	99.1		%	98.7		%
Undistributed earnings — common shares	147,391			148,057			111,286
Add: dividends declared and paid — common shares	94,824			83,351			74,202
Numerator for basic and diluted earnings per common share	$	242,215		$	231,408		$	185,488
Denominator:
Basic earnings per common share — weighted average common shares outstanding	155,363,848			155,736,384			152,462,514
Incremental shares for stock options and employee stock purchase plan — weighted average assumed conversion	1,453,804			1,288,620			2,227,671
Diluted earnings per common share — adjusted weighted average shares and assumed conversion	156,817,652			157,025,004			154,690,185
Per common share net income:
Basic	$	1.56		$	1.49		$	1.22
Diluted	$	1.54		$	1.47		$	1.20

____________________________



(a)	Weighted average common shares outstanding	155,363,848		155,736,384		152,462,514
	Weighted average restricted shares (participating securities)	1,277,128		1,472,967		1,976,505
	Total	156,640,976		157,209,351		154,439,019
	Percentage allocated to common shares	99.2	%	99.1	%	98.7	%

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The incremental shares for stock options and the ESPP are included in the diluted earnings per share calculation using the treasury stock method, unless the effect of including them would be anti-dilutive. The outstanding stock options and ESPP shares and the anti-dilutive stock options and ESPP shares excluded from the diluted earnings per share calculations were as follows:



	2014	2013	2012
Outstanding stock options and ESPP shares (as of December 31)	4,603,292	5,169,828	4,810,287
Anti-dilutive stock options and ESPP shares (for the year ended December 31)	550,178	912,570	1,697,835

Stock Split

Below are the effects of the stock split on earnings per share for the years ended December 31, 2013 and 2012:



(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
For the year ended December 31, 2012
Numerator for basic and diluted earnings per common share	$	185,488	$	—		$	185,488
Denominator:
Basic earnings per common share — weighted average common shares	50,820,838		101,641,676			152,462,514
Incremental shares for stock options and employee stock purchase plan	742,557		1,485,114			2,227,671
Diluted earnings per common share — adjusted weighted average shares and assumed conversion	51,563,395		103,126,790			154,690,185
Per common share net income:
Basic	$	3.65	$	(2.43	)	$	1.22
Diluted	$	3.60	$	(2.40	)	$	1.20

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Below are the effects of the stock split on other disclosures included for earnings per share for the years ended December 31, 2013 and 2012:

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	%
For the year ended December 31, 2012
Weighted-average common shares outstanding	50,820,838		101,641,676		152,462,514
Weighted-average restricted shares (participating securities)	658,835		1,317,670		1,976,505
Total	51,479,673		102,959,346		154,439,019
Percentage allocated to common shares	98.7	%	—	%	98.7	%

Outstanding and Anti-dilutive Stock Options and ESPP Shares

The outstanding stock options and the ESPP shares as of December 31, 2013 and 2012 and the anti-dilutive stock options and ESPP shares excluded from the diluted earnings per share calculations for the years ended December 31, 2013 and 2012 were 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
As of and for the year ended December 31, 2012
Outstanding stock options and ESPP shares	1,603,429	3,206,858	4,810,287
Anti-dilutive stock options and ESPP shares	565,945	1,131,890	1,697,835

Impacts of the Accelerated Share Repurchase Program

The basic shares outstanding as of December 31, 2014 include the impact of the 3.6 million shares received under the ASR program, as described in Note 13.

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)	2014			2013			2012
Income tax expense at 35% statutory rate	$	138,042		$	123,329		$	103,778
State income taxes (net of federal benefit)	16,054			9,110			6,247
AFUDC equity	(6,201		)	(9,715		)	(7,207		)
Entergy Transaction expenses (a)	—			(5,614		)	4,113
Other — net	2,427			1,752			1,701
Total income tax provision	$	150,322		$	118,862		$	108,632

____________________________


(a)	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 that were incurred in 2012 and 2011. See Note 17 for discussion of the Entergy Transaction.

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Components of the income tax provision were as follows:



(In thousands)	2014		2013		2012
Current income tax expense	$	59,949	$	42,159	$	41,347
Deferred income tax expense	90,313		76,094		66,710
Benefits of operating loss carryforward	60		609		575
Total income tax provision	$	150,322	$	118,862	$	108,632

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 tax assets and liabilities are classified as current or non-current according to the classification of the related assets or liabilities. Deferred tax assets and liabilities not related to assets or liabilities are classified according to the expected reversal date of the temporary differences.

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



(In thousands)	2014			2013
Property, plant and equipment	$	(560,960	)	$	(459,983	)
METC regulatory deferral (a)	(12,721		)	(13,743		)
Acquisition adjustments — ADIT deferrals (a)	(15,164		)	(14,945		)
Goodwill	(133,138		)	(117,493		)
Net revenue accruals and deferrals, including accrued interest (a)	22,047			23,504
Pension and postretirement liabilities	14,196			11,864
State income tax NOLs (net of federal benefit)	20,004			16,573
Share-based compensation	12,211			12,040
Other — net	11,474			(3,530		)
Net deferred tax liabilities	$	(642,051	)	$	(545,713	)
Gross deferred income tax liabilities	$	(810,141	)	$	(674,172	)
Gross deferred income tax assets	168,090			128,459
Net deferred tax liabilities	$	(642,051	)	$	(545,713	)

____________________________

(a)Described in Note 5.

We have state income tax net operating losses (“NOLs”) as of December 31, 2014, 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 $7.1 million tax effected, net of federal benefit, as of December 31, 2014 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 the tax deductions that exceed book value be recognized only if that deduction reduces taxes payable as a result of a realized cash benefit from the deduction.

11. RETIREMENT BENEFITS AND ASSETS HELD IN TRUST

Pension Plan Benefits

We have a qualified defined benefit pension plan for eligible employees, comprised of a traditional final average pay plan and a cash balance plan (“retirement 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 qualified 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 $3.8 million, $6.9 million and $7.0 million to the retirement plan in 2014, 2013 and 2012, respectively. We expect to contribute up to $4.0 million to the retirement plan in 2015.

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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 $26.5 million and $21.1 million at December 31, 2014 and 2013, respectively, are not included in the retirement plan asset amounts presented below, but are included in other assets on our consolidated statement of financial position. For the years ended December 31, 2014, 2013 and 2012, we contributed $5.1 million, $0.6 million and $4.7 million, respectively, to these supplemental benefit plans.

Prior to August 2013, the investments held for the supplemental benefit plans were classified as trading securities and the net realized and unrealized loss of $1.8 million in 2013 was recorded as other expense and the net realized and unrealized gains of $1.9 million in 2012 was recorded as other income. In August 2013, the investments were sold and reinvested into new funds, and at acquisition, based on our evaluation of the intent of the new investments, we classified them as available-for-sale consistent with the FASB guidance. As of December 31, 2014, all of our investments held in the supplemental benefit plans were classified as available-for-sale securities and the net unrealized gains of $0.1 million 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	2014		2013
Fixed income securities	48.8	%	47.7	%
Equity securities	51.2	%	52.3	%
Total	100.0	%	100.0	%

Net periodic benefit cost for the pension plans during 2014, 2013 and 2012 was as follows by component:



(In thousands)	2014			2013			2012
Service cost	$	5,066		$	5,261		$	4,160
Interest cost	3,603			2,792			2,590
Expected return on plan assets	(3,541		)	(2,868		)	(2,277		)
Amortization of prior service credit	(42		)	(42		)	(42		)
Amortization of unrecognized loss	1,545			2,714			3,470
Net pension cost	$	6,631		$	7,857		$	7,901

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The following table reconciles the obligations, assets and funded status of the pension plans as well as the amounts recognized as accrued pension liability in the consolidated statement of financial position as of December 31, 2014 and 2013:



(In thousands)	2014			2013
Change in Benefit Obligation:
Beginning projected benefit obligation	$	(73,468	)	$	(72,400	)
Service cost	(5,066		)	(5,261		)
Interest cost	(3,603		)	(2,792		)
Actuarial net (loss) gain	(14,937		)	6,161
Benefits paid	1,334			824
Ending projected benefit obligation	$	(95,740	)	$	(73,468	)
Change in Plans’ Assets:
Beginning plan assets at fair value	$	48,894		$	38,130
Actual return on plan assets	4,851			4,650
Employer contributions	3,822			6,938
Benefits paid	(1,177		)	(824		)
Ending plan assets at fair value	$	56,390		$	48,894
Funded status, underfunded	$	(39,350	)	$	(24,574	)
Accumulated benefit obligation	$	(84,533	)	$	(61,832	)
Amounts recorded as:
Funded Status:
Accrued pension liabilities	$	(44,033	)	$	(35,003	)
Pension assets — other assets — other	4,683			10,429
Total	$	(39,350	)	$	(24,574	)
Accumulated benefit obligation:
Retirement plan	$	(48,571	)	$	(36,033	)
Supplemental benefit plans	(35,962		)	(25,799		)
Total	$	(84,533	)	$	(61,832	)
Unrecognized Amounts in Non-current Regulatory Assets:
Net actuarial loss	$	24,868		$	12,787
Prior service credit	25			(17		)
Total	$	24,893		$	12,770

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 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.

Actuarial assumptions used to determine the benefit obligation for the pension plans for 2014, 2013 and 2012 are as follows:



	2014	2013	2012
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%

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Actuarial assumptions used to determine the benefit cost for 2014, 2013 and 2012 for the pension plans are as follows:



	2014	2013	2012
Discount rate	4.60 - 5.10%	3.70 - 4.45%	4.50 - 5.00%
Annual rate of salary increases	4.00 - 6.00%	5.00 - 6.00%	5.00 - 6.00%
Expected long-term rate of return on plan assets	6.75%	7.00%	7.25%

At December 31, 2014, 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)
2015	$	1,767
2016	1,722
2017	5,419
2018	5,498
2019	5,904
2020 through 2024	36,957

Investment Objectives and Fair Value Measurement

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

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

The measurement of fair value is based on a three-tier hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. Changes in economic conditions or model-based valuation techniques may require the transfer of financial instruments from one fair value level to another. In such instances, the transfer is reported at the beginning of the reporting period. For the years ended December 31, 2014 and 2013, there were no transfers between levels.

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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 fair value measurement of the retirement plan assets as of December 31, 2013, 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	$	20,639	$	—	$	—
Mutual funds — international equity securities	4,956		—		—
Mutual funds — fixed income securities	19,813		—		—
Guaranteed deposit fund	—		3,486		—
Total	$	45,408	$	3,486	$	—

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 is a group annuity contract and is valued at estimated fair value by discounting the related cash flows based on current yields of similar instruments with comparable durations that are quoted in active markets.

Other Postretirement Benefits

We provide certain postretirement health care, dental, and life insurance benefits for eligible employees. We contributed $6.3 million, $1.5 million and $4.4 million to the postretirement benefit plan in 2014, 2013 and 2012, respectively. We expect to contribute up to $9.0 million to the plan in 2015.

The plan assets consisted of the following assets by category:



Asset Category	2014		2013
Fixed income securities	57.2	%	46.6	%
Equity securities	42.8	%	53.4	%
Total	100.0	%	100.0	%

Our measurement of the accumulated postretirement benefit obligation as of December 31, 2014 and 2013 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 2014, 2013 and 2012 was as follows by component:



(In thousands)	2014			2013			2012
Service cost	$	5,846		$	5,774		$	5,433
Interest cost	1,991			1,562			1,552
Expected return on plan assets	(1,361		)	(1,415		)	(1,016		)
Amortization of prior service cost	—			—			125
Amortization of unrecognized loss	—			220			534
Net postretirement cost	$	6,476		$	6,141		$	6,628

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 statement of financial position as of December 31, 2014 and 2013:



(In thousands)	2014			2013
Change in Benefit Obligation:
Beginning accumulated postretirement obligation	$	(42,706	)	$	(37,015	)
Service cost	(5,846		)	(5,774		)
Interest cost	(1,991		)	(1,562		)
Actuarial net (loss) gain	(7,695		)	1,491
Benefits paid	311			154
Ending accumulated postretirement obligation	$	(57,927	)	$	(42,706	)
Change in Plan’s Assets:
Beginning plan assets at fair value	$	24,004		$	19,670
Actual return on plan assets	2,107			2,857
Employer contributions	6,286			1,477
Employer provided retiree premiums	311			154
Benefits paid	(311		)	(154		)
Ending plan assets at fair value	$	32,397		$	24,004
Funded status, underfunded	$	(25,530	)	$	(18,702	)
Amounts recorded as:
Funded Status:
Accrued postretirement liabilities	$	(25,530	)	$	(18,702	)
Total	$	(25,530	)	$	(18,702	)
Unrecognized Amounts in Non-current Regulatory Assets:
Net actuarial loss	$	9,258		$	2,309
Total	$	9,258		$	2,309

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Actuarial assumptions used to determine the benefit obligation for 2014, 2013 and 2012 are as follows:



	2014	2013	2012
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
Annual rate of increase in dental benefit costs	5.00%	5.00%	5.00%

Actuarial assumptions used to determine the benefit cost for 2014, 2013 and 2012 are as follows:



	2014	2013	2012
Discount rate	5.15%	4.20%	5.00%
Annual rate of salary increases	4.00%	5.00%	5.00%
Health care cost trend rate assumed for next year	7.50%	8.00%	9.00%
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	2017	2017
Expected long-term rate of return on plan assets	5.00 - 6.75%	7.00%	7.25%

At December 31, 2014, 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)
2015	$	450
2016	566
2017	713
2018	1,041
2019	1,373
2020 through 2024	12,833

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 2014 and the postretirement benefit obligation at December 31, 2014:



	One-Percentage-		One-Percentage-
(In thousands)	Point Increase		Point Decrease
Effect on total of service and interest cost	$	1,686	$	(1,322	)
Effect on postretirement benefit obligation	12,643		(9,838		)

Investment Objectives and Fair Value Measurement

The general investment objectives of the other postretirement benefit plan includes 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 and considering 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, 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	$	—

The fair value measurement of the other postretirement benefit plan assets as of December 31, 2013, 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	$	519	$	—	$	—
Mutual funds — U.S. equity securities	12,113		—		—
Mutual funds — international equity securities	713		—		—
Mutual funds — fixed income securities	10,127		—		—
Guaranteed deposit fund	—		532		—
Total	$	23,472	$	532	$	—

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 is a group annuity contract and is 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 represents the net asset value. As of December 31, 2014 and 2013, 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 $4.5 million, $4.5 million and $3.8 million in 2014, 2013 and 2012, respectively.

12. FAIR VALUE MEASUREMENTS

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	)	$	—

Our assets measured at fair value subject to the three-tier hierarchy at December 31, 2013, 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	$	19,000	$	—	$	—
Mutual funds — fixed income securities	21,318		—		—
Mutual funds — equity securities	516		—		—
Total	$	40,834	$	—	$	—

As of December 31, 2014 and 2013, 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 mutual funds that are administered similar to money market funds recorded at cost plus accrued interest to approximate fair value. Our 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. Changes in the observed trading prices and liquidity of money market funds are monitored as additional support for determining fair value, and losses are recorded in earnings for investments classified as trading securities and other comprehensive income for investments classified as available-for-sale if fair value falls below recorded cost.

The liability related to derivatives consists of interest rate swaps as discussed in Note 8. The fair value of our interest rate swap derivatives as of December 31, 2014 is determined based on a discounted cash flow (“DCF”) method using LIBOR swap rates which are observable at commonly quoted intervals.

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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, 2014 and 2013.

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 our revolving and term loan credit agreements, was $3,985.6 million and $3,299.0 million at December 31, 2014 and 2013, 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, excluding our revolving and term loan credit agreements, was $3,629.8 million and $3,100.9 million at December 31, 2014 and 2013, respectively.

Revolving and Term Loan Credit Agreements

At December 31, 2014 and 2013, we had a consolidated total of $473.8 million and $511.2 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 and special deposits, approximates their fair value due to the short-term nature of these instruments.

13. STOCKHOLDERS' EQUITY

Common Stock

General — At December 31, 2014, 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, 2014, there were 155,140,967 shares of our common stock outstanding (which includes restricted stock), no shares of preferred stock outstanding and 797 holders of record of our common stock.

Stock Split — In January 2014, we filed an amendment to our Articles of Incorporation, as previously approved by our shareholders, to increase the number of authorized shares of common stock to 300 million shares. 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. As a result of the stock split and other issuances and retirements during the year ended December 31, 2014, our outstanding shares increased from approximately 52.5 million shares (unadjusted for the three-for-one stock split) as of December 31, 2013 to 155,140,967 shares as of December 31, 2014. In addition, all unvested restricted stock awards, outstanding stock option awards and share reserves under our share-based compensation plans as discussed in Note 14 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, the Board of Directors authorized a share repurchase program for up to $250.0 million, which expires in December 2015. On June 19, 2014, ITC Holdings entered into an accelerated share repurchase agreement (the “ASR program”) with JP Morgan Chase (“JP Morgan”) for up to $150.0 million, with a minimum commitment of $130.0 million. Under the ASR program, ITC Holdings advanced $150.0 million to JP Morgan 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 ASR program. On December 22, 2014, the ASR program was settled for $130.0 million and ITC Holdings received an

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additional 0.7 million shares as determined by the volume-weighted average share price during the term of the 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.

Voting Rights — Each holder of ITC Holdings’ common stock, including holders of our common stock subject to restricted stock 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 awards, are entitled to receive dividends or other distributions declared by the board of directors. 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 other subsidiaries we may have and 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 other subsidiaries we may have to pay dividends and make other payments to ITC Holdings 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.

The note purchase agreements governing ITC Holdings’ Term Loan Credit Agreement and Senior Notes 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 because of restrictions which limit the payment of dividends to ITC Holdings by its subsidiaries. Each of our Regulated Operating Subsidiaries as of December 31, 2014 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.” Management does not expect that maintaining this targeted capital structure will have an impact on the Company's 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 2014, 2013 and 2012, we repurchased 3,673,226, 163,320 and 298,599 shares of common stock for an aggregate of $134.3 million, $4.9 million and $7.3 million, respectively, which represented shares of common stock delivered to us by employees as payment of tax withholdings due to us upon the vesting of restricted stock in addition to shares delivered under the ASR program described above.

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Accumulated Other Comprehensive Income

The following table provides the components of changes in AOCI for the years ended December 31, 2014, 2013 and 2012:



	Year Ended December 31,
(In thousands)	2014			2013			2012
Balance at the beginning of period	$	6,327		$	(18,048	)	$	(15,368	)
Derivative instruments
Reclassification of net (loss) gain relating to interest rate cash flow hedges from AOCI to interest expense — net (net of tax of $349, $436 and $31 for the years ended December 31, 2014, 2013 and 2012, respectively)	445			(25		)	67
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			—			—
Gain (loss) on interest rate swaps relating to interest rate cash flow hedges (net of tax of $1,465, $15,652 and $1,777 for the years ended December 31, 2014, 2013 and 2012, respectively)	(2,041		)	24,329			(2,747		)
Derivative instruments, net of tax	(1,479		)	24,304			(2,680		)
Available-for-sale securities
Unrealized gain (loss) on available-for-sale securities (net of tax of $18 and $46 for the years ended December 31, 2014 and 2013, respectively)	(32		)	71			—
Available-for-sale securities, net of tax	(32		)	71			—
Total other comprehensive (loss) income, net of tax	(1,511		)	24,375			(2,680		)
Balance at the end of period	$	4,816		$	6,327		$	(18,048	)

ITC Holdings Sales Agency Financing Agreement

On July 27, 2011, ITC Holdings entered into a Sales Agency Financing Agreement (the “SAFA”). Under the terms of the SAFA, ITC Holdings was able to issue and sell shares of common stock, without par value, from time to time, up to an aggregate sales proceeds amount of $250.0 million. No shares were issued under the SAFA prior to its expiration on July 27, 2014.

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 LTIP, which was adopted in 2006 and most recently amended and restated in 2011, permits the compensation committee to make grants of a variety of share-based awards (such as options, restricted shares and deferred stock units) for a cumulative amount of up to 14,850,000 shares to employees, directors and consultants. The LTIP provides that no more than 9,750,000 of the shares may be granted as awards to be settled in shares of common stock other than options or stock appreciation rights. No awards would be permitted after February 7, 2016. Prior to the adoption of the LTIP, we made various share-based awards under the 2003 Plan, including options and restricted stock. In addition, our board of directors and shareholders approved the ESPP, which we implemented effective April 1, 2007 and most recently amended on May 21, 2014. The ESPP allows for the issuance of an aggregate of 665,000 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 grants, employee ESPP purchases and settlement of deferred stock units. As of December 31, 2014, 4,999,110 shares were available for future issuance under our LTIP and ESPP, including 4,603,292 shares issuable upon the exercise of outstanding stock options, of which 3,198,528 were vested.

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We recorded share-based compensation in 2014, 2013 and 2012 as follows:



(In thousands)	2014		2013		2012
Operation and maintenance expenses	$	1,444	$	1,617	$	1,933
General and administrative expenses	8,549		9,318		8,057
Amounts capitalized to property, plant and equipment	4,659		4,731		5,632
Total share-based compensation	$	14,652	$	15,666	$	15,622
Total tax benefit recognized in the consolidated statement of operations	$	4,182	$	4,557	$	3,807

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, 2014, 2013 and 2012, we recognized the tax effects of the excess tax deductions as an increase in common stock of $7.8 million, $4.3 million and $23.0 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 2014 was as follows:



			Weighted
	Number of		Average
	Options		Exercise Price
Outstanding at January 1, 2014 (3,385,620 exercisable with a weighted average exercise price of $14.33)	5,169,828		$	18.53
Granted	652,900		36.73
Exercised	(1,011,750	)	18.43
Forfeited	(207,686	)	28.00
Outstanding at December 31, 2014 (3,198,528 exercisable with a weighted average exercise price of $15.98)	4,603,292		$	20.71

Grant date fair value of the stock options awards granted during 2014, 2013 and 2012 was determined using a Black-Scholes option pricing model. The following assumptions were used in determining the weighted average fair value per option:



	2014			2013			2012
	Option Grants			Option Grants			Option Grants
Weighted average grant date fair value per option	$	8.92		$	7.06		$	5.53
Weighted average expected volatility (a)	27.2		%	29.3		%	29.8		%
Weighted average risk-free interest rate	1.8		%	1.1		%	1.0		%
Weighted average expected term (b)	6 years			6 years			6 years
Weighted average expected dividend yield	1.55		%	1.72		%	1.99		%
Estimated fair value of underlying shares	$	36.73		$	29.31		$	23.59

____________________________


(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.

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At December 31, 2014, the aggregate intrinsic value and the weighted average remaining contractual term for all outstanding options were approximately $90.8 million and 5.3 years, respectively. At December 31, 2014, the aggregate intrinsic value and the weighted average remaining contractual term for exercisable options were $78.2 million and 3.9 years, respectively. The aggregate intrinsic value of options exercised during 2014, 2013 and 2012 was $18.5 million, $53.2 million and $53.2 million, respectively. At December 31, 2014, the total unrecognized compensation cost related to the unvested options awards was $6.3 million and the weighted average period over which it is expected to be recognized was 1.9 years.

We estimate that 4,494,995 of the options outstanding at December 31, 2014 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, 2014 was $20.45 per share, $89.8 million and 5.3 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. The weighted average expected remaining vesting period at December 31, 2014 is 1.5 years. 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 accounted for as unearned compensation, with amounts amortized over the vesting period.

Restricted stock award activity for 2014 was as follows:



	Number of		Weighted
	Restricted		Average
	Stock		Grant Date
	Awards		Fair Value
Unvested restricted stock awards at January 1, 2014	1,386,966		$	24.32
Granted	321,139		36.75
Vested	(395,565	)	21.53
Forfeited	(88,721	)	26.03
Unvested restricted stock awards at December 31, 2014	1,223,819		$	28.37

The weighted average grant date fair value of restricted stock awarded during 2013 and 2012 was $29.42 and $23.88 per share, respectively. The aggregate fair value of restricted stock awards as of December 31, 2014 was $49.5 million. The aggregate fair value of restricted stock awards that vested during 2014, 2013 and 2012 was $14.4 million, $15.8 million and $25.1 million, respectively. At December 31, 2014, the total unrecognized compensation cost related to the restricted stock awards was $18.2 million and the weighted average period over which that cost is expected to be recognized was 2.2 years.

As of December 31, 2014, we estimate that 1,081,166 shares of the restricted shares outstanding at December 31, 2014 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 $28.15 per share, $43.7 million and 1.5 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 expense 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 2014, 2013 and 2012, employees purchased 69,230, 77,097 and 76,563 shares, respectively, resulting in proceeds from the sale of our common stock of $2.1 million, $1.9 million and $1.6 million, respectively, under the ESPP. The total share-based compensation amortization for the ESPP was $0.5 million, $0.4 million and $0.4 million for the years ended December 31, 2014, 2013 and 2012, 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

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for our percentage of ownership interest. Various agreements provide the authority for construction of capital improvements and for 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 expense on our consolidated statement of operations.

We have investments in jointly owned utility assets as shown in the table below as of December 31, 2014:



	Net		Construction
(In thousands)	Investments (a)		Work in Progress
Substations	$	30,842	$	931
Lines	100,591		3,640
Total	$	131,433	$	4,571

____________________________


(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 $28.4 million (including $0.8 million of jointly owned lines under construction) as of December 31, 2014. The municipal power agency’s ownership portion entitles them to approximately 234 MW of network transmission service over 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, 2014, METC had net investments in jointly owned assets within substations totaling $13.4 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 over the METC transmission system. As of December 31, 2014, 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%.

ITC Midwest

ITC Midwest has joint sharing of several substations and transmission lines with various parties. As of December 31, 2014, ITC Midwest had net investments in jointly shared substations facilities totaling $17.8 million (including $0.4 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, 2014, ITC Midwest had net investments in jointly shared transmission lines totaling $32.8 million (including $0.7 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% 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

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costs. As of December 31, 2014, ITC Great Plains had net investment in the project that is currently under construction of $2.6 million of which ITC Great Plains ownership percentage was 51%.

16. COMMITMENTS AND CONTINGENT LIABILITIES

Environmental Matters

Our Regulated Operating Subsidiaries’ operations 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 hazardous materials and of solid and hazardous wastes, and impose obligations to investigate and remediate contamination in certain circumstances. Liabilities to investigate or remediate 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 at properties currently owned or operated by our Regulated Operating Subsidiaries. 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. 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 Regulated Operating Subsidiaries’ costs for such compliance in a manner that would be expected to have a material adverse effect on our results of operations, financial position or liquidity.

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

Some properties in which our Regulated Operating Subsidiaries have an ownership interest or at which they operate are, and others are suspected of being, affected by environmental contamination. Our Regulated Operating Subsidiaries are not aware of any pending or threatened claims against them with respect to environmental contamination, or of any investigation or remediation of contamination at any properties, that entail costs likely to materially affect them. 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 our Regulated Operating Subsidiaries do not believe that a causal link between electromagnetic field exposure and injury has been generally established and accepted in the scientific community, if such a relationship is established or accepted, the liabilities and costs imposed on our business could be significant. We are not aware of any pending or threatened claims against our Regulated Operating Subsidiaries for bodily injury, disease or other damages allegedly related to exposure to electromagnetic fields and electric transmission and distribution lines that entail costs likely to have a material adverse effect on our results of operations, financial position or liquidity.

Litigation

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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 use of the industrial processing exemption from use tax it has taken beginning January 1, 2007.

ITCTransmission believes that its utilization of the industrial processing exemption is appropriate and intends to defend itself against the denial of such exemption through certain administrative and judicial appeal rights. However, it is reasonably possible that the assessment of additional use tax could be sustained after all administrative appeals and litigation have been exhausted.

The amount of use tax liability associated with the exemptions taken by ITCTransmission through December 31, 2014 is estimated to be approximately $15.5 million, including interest. This amount includes approximately $10.0 million, including interest, assessed or preliminarily assessed for the audit periods noted above. ITCTransmission has not recorded this contingent liability as of December 31, 2014. METC has also taken the industrial processing exemption, estimated to be approximately $10.6 million for periods still subject to audit and METC has also not recorded any contingent liabilities as of December 31, 2014 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.

FERC Audit Refund

In 2011, the FERC issued an order that identified certain findings and recommendations of certain staff of the FERC relating to specific aspects of the accounting treatment for the acquisition of the transmission assets of IP&L by ITC Midwest that required adjustments to the MISO Regulated Operating Subsidiaries’ respective annual revenue requirement calculations and resulted in corresponding refunds. ITC Midwest, ITCTransmission and METC recorded an aggregate regulatory liability for the refund and related interest of $13.1 million as of December 31, 2013. The amounts were fully refunded through the cost-based formula rates in 2014.

Rate of Return on Equity and Capital Structure Complaint

On November 12, 2013, the Association of Businesses Advocating Tariff Equity, Coalition of MISO Transmission Customers, Illinois Industrial Energy Consumers, Indiana Industrial Energy Consumers, Inc., Minnesota Large Industrial Group, and Wisconsin Industrial Energy Group (collectively, the “complainants”) filed a complaint with the FERC under Section 206 of the FPA (the “Complaint”), requesting that the FERC find the current 12.38% MISO regional base ROE rate for all MISO TOs, including ITCTransmission, METC and ITC Midwest to no longer be just and reasonable. The complainant sought a FERC order reducing the regional base ROE rate used in our MISO Regulated Operating Subsidiaries’ formula transmission rates to 9.15%. The 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 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 transmission owners, are no longer just and reasonable, and sought to have them eliminated.

On January 6, 2014, our MISO Regulated Operating Subsidiaries filed responses to the Complaint with the FERC (both jointly with other MISO TOs and through a separate supplemental response), supporting the current regional base ROE rate as just and reasonable, the use of current individual company capital structures, and the use of approved ROE adders for RTO membership and independence. The responses sought dismissal of the Complaint, asserting that the complainants failed to meet their burden under Section 206 of the FPA to show that the current regional base ROE rate, approved capital structures and ROE adders approved for ITCTransmission and METC are no longer just and reasonable.

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

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

On October 16, 2014, FERC granted the complainants’ request in part by setting the MISO regional base ROE rate for hearing and settlement procedures, while denying all other aspects of the Complaint. FERC found the joint complainants failed to show that the use of actual or FERC-approved capital structures that include more than 50% equity are unjust and unreasonable. FERC also denied the request to terminate ITCTransmission’s and METC’s ROE incentives. The order again reiterates 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.

We believe it is probable that a refund will be required for the Initial Refund Period, and the estimated range of refunds is expected to be from $47.8 million to $88.1 million for the period from November 12, 2013 through December 31, 2014. During the fourth quarter of 2014, ITCTransmission, METC, and ITC Midwest recorded an aggregate estimated regulatory liability of$47.8 million for the potential refunds as of December 31, 2014, as there is no best estimate within the range of refunds. This amount has been recorded as a reduction of revenues of $46.9 million and an increase in interest expense of $0.9 million in the consolidated statements of operations, and resulted in an estimated after-tax reduction of net income of $28.9 million for the year ended December 31, 2014. Based on the estimated range of refunds identified above, we believe that it is reasonably possible that this matter could result in an additional pre-tax refund of up to $40.3 million (or a $24.4 million after-tax reduction of net income) in excess of the amount recorded as of December 31, 2014. It is also possible the outcome of this matter could differ from the estimated range of losses and materially affect our results of operations due to the uncertainty of the calculation of an authorized ROE rate along with the zone of reasonableness under the newly adopted two-step DCF methodology, which is subject to significant discretion by the FERC.

Purchase Obligations and Leases

At December 31, 2014, we had purchase obligations of $44.2 million representing commitments for materials, services and equipment that had not been received as of December 31, 2014, 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 that are expected to be paid for in 2015.

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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 $1.0 million, $0.8 million and $0.7 million for the years ended December 31, 2014, 2013 and 2012, respectively, recorded in general and administrative and 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, 2014 were:



(In thousands)
2015	$	850
2016	800
2017	753
2018	632
2019 and thereafter	2,400
Total minimum lease payments	$	5,435

Other Commitments

Nonconsolidated Variable Interest Entity

We have an agreement with Utility Lines Construction Services, Inc. (“ULCS”), which is a division of Asplundh Tree Expert Co., to perform the majority of maintenance for all of our Regulated Operating Subsidiaries. The agreement between us and ULCS contains a variable component related to a cost-plus arrangement which is a consideration for consolidation. However, we are not subject to risk of loss from ULCS’ operations and have not provided, nor will we provide, any significant financial support other than contractual payments. We have evaluated the agreement for possible consolidation, including review of qualitative factors such as the length and terms of the agreement, and have concluded that ULCS is not required to be consolidated in our consolidated financial statements.

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 in 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 expense.

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 and the value of activities associated with other uses of the infrastructure (such as for fiber optics, telecommunications and gas pipelines). 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 expense.

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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 amended June 20, 2013, 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.

Maintenance Agreement. Midwest Energy, Inc. (“Midwest Energy”) and ITC Great Plains entered into a maintenance agreement (the “Midwest Energy Agreement”) dated as of June 25, 2012, pursuant to which Midwest Energy agreed to perform various field operations and maintenance service related to ITC Great Plains facilities associated with the KETA project. The Midwest Energy Agreement had an initial term of three years with automatic three-year renewals unless terminated (1) due to a material breach by the non-terminating party following notice and failure to cure or (2) by mutual consent of the parties. In December 2014, ITC Great Plains and Midwest Energy mutually agreed to terminate the Midwest Energy Agreement. Services will continue to be provided through the effective termination date of June 24, 2015.

Concentration of Credit Risk

Our credit risk is primarily with DTE Electric, Consumers Energy and IP&L, which were responsible for approximately 22.2%, 24.2% and 29.0%, respectively, or $224.5 million, $244.7 million and $292.9 million, respectively, of our consolidated billed revenues for the year ended December 31, 2014. These percentages and amounts of total billed revenues of DTE Electric, Consumers Energy and IP&L include the collection of 2012 revenue accruals and deferrals and exclude any amounts for the 2014 revenue accruals and deferrals that were included in our 2014 operating revenues, but will not be billed to our customers until 2016. Any financial difficulties experienced by DTE Electric, Consumers Energy or IP&L could negatively impact our business. MISO, as our MISO Regulated Operating Subsidiaries’ billing agent, bills DTE Electric, Consumers Energy, IP&L and other customers on a monthly basis and collects fees for the use of our transmission systems. SPP bills customers of ITC Great Plains on a monthly basis and collects fees for the use of ITC Great Plains’ assets. MISO and SPP have implemented strict credit policies for its members’ customers, which include customers using our transmission systems. Specifically, MISO and SPP require a letter of credit or cash deposit equal to the credit exposure, which is determined by a credit scoring model and other factors, from any customer using a member’s transmission system.

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, 2013 and 2012, we expensed external legal, advisory and financial services fees related to the terminated Entergy Transaction of $0.4 million, $43.1 million and $19.4 million, respectively, and certain internal labor and associated costs related to the terminated Entergy Transaction of $0.7 million, $7.8 million and $7.1 million, respectively. 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/
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)	6,867,411		3,944,318			(3,837,640		)	6,974,089
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)	6,174,888		3,619,759			(3,512,404		)	6,282,243
Capital expenditures	824,165		2,208			(4,785		)	821,588

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	Regulated
	Operating		ITC Holdings			Reconciliations/
2012	Subsidiaries		and Other			Eliminations			Total
(In thousands)
Operating revenues	$	830,616	$	607		$	(688	)	$	830,535
Depreciation and amortization	105,841		671			—			106,512
Interest expense — net	65,445		90,289			—			155,734
Income (loss) before income taxes	422,074		(125,566		)	—			296,508
Income tax provision (benefit)	159,528		(50,896		)	—			108,632
Net income	262,545		187,876			(262,545		)	187,876
Property, plant and equipment — net	4,123,520		11,059			—			4,134,579
Goodwill	950,163		—			—			950,163
Total assets (a)	5,440,401		3,252,047			(3,127,639		)	5,564,809
Capital expenditures	806,825		243			(4,305		)	802,763

____________________________


(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.

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
2014
Operating revenues (a)	$	258,603	$	263,214	$	270,134	$	231,097	$	1,023,048
Operating income (a)(b)	153,441		158,928		161,432		119,028		592,829
Net income (a)(b)(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
2013
Operating revenues	$	217,304	$	229,817	$	238,782	$	255,369	$	941,272
Operating income (b)	112,881		110,994		130,822		141,364		496,061
Net income (b)(d)	50,190		47,395		58,984		76,937		233,506
Basic earnings per share	$	0.32	$	0.30	$	0.37	$	0.49	$	1.49
Diluted earnings per share	$	0.32	$	0.30	$	0.37	$	0.48	$	1.47

____________________________


(a)	During the fourth quarter of 2014, we established a refund reserve at our MISO Regulated Operating Subsidiaries related to the rate of return on equity and capital structure complaint as described in Note 16, which resulted in a reduction in operating revenues and operating income of $46.9 million and an estimated $28.9 million reduction to net income.

(b)

During the years ended December 31, 2014 and 2013, we expensed external legal, advisory and financial services fees of $0.4 million and $43.1 million, respectively, and internal labor and related costs of approximately $0.7 million and $7.8 million, respectively, related to the Entergy Transaction, which reduced operating income. These expenses, including the fourth quarter 2013 effects described below, resulted in an estimated reduction to net income of $0.7 million and $22.7 million for the years ended December 31, 2014 and 2013, respectively. The external and internal costs related to the Entergy Transaction are not included as components of revenue requirement at our Regulated Operating Subsidiaries as they were incurred at ITC Holdings.

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(c)	During the year ended December 31, 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.


(d)	During the fourth quarter of 2013, we recognized a reduction in income tax provision and a corresponding increase in net income of $13.1 million, respectively, for the external costs related to the Entergy transaction that originally were recorded as non-deductible for income tax provision purposes.


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, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION.

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.

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.

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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 LTIP, issues shares to employees under the ESPP, and previously made equity-based grants to employees and directors under the 2003 Plan, 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, 2014 (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	4,603	$	20.71	4,999

____________________________

(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, 2014 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 restricted stock awards granted that have not been forfeited. The LTIP imposes a separate restriction so that no more than 9,750,000 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, 2014 and 2013
		Consolidated Statements of Operations for the Years Ended December 31, 2014, 2013 and 2012
		Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2014, 2013 and 2012
		Consolidated Statements of Changes in Stockholders’ Equity for the Years Ended December 31, 2014, 2013 and 2012
		Consolidated Statements of Cash Flows for the Years Ended December 31, 2014, 2013 and 2012
		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)	2014		2013
ASSETS
Current assets
Cash and cash equivalents	$	6,305	$	26,853
Accounts receivable from subsidiaries	42,665		50,196
Prepaid and other current assets	3,145		7,302
Total current assets	52,115		84,351
Other assets
Investment in subsidiaries	3,784,609		3,450,989
Deferred income taxes	24,397		25,519
Deferred financing fees (net of accumulated amortization of $4,700 and $6,346, respectively)	14,117		11,241
Other	67,376		47,660
Total other assets	3,890,499		3,535,409
TOTAL ASSETS	$	3,942,614	$	3,619,760
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	2,431	$	6,300
Accrued payroll	23,502		21,930
Accrued interest	34,815		37,486
Accrued taxes	3,146		37
Debt maturing within one year	—		50,000
Other	1,120		3,546
Total current liabilities	65,014		119,299
Accrued pension and postretirement liabilities	69,562		53,704
Other	3,237		1,106
Long-term debt (net of discounts of $3,940 and $3,082, respectively)	2,135,244		1,831,918
STOCKHOLDERS’ EQUITY
Common stock, without par value, 300,000,000 shares authorized, 155,140,967 and 157,500,795 shares issued and outstanding at December 31, 2014 and 2013, respectively	923,191		1,014,435
Retained earnings	741,550		592,971
Accumulated other comprehensive income	4,816		6,327
Total stockholders’ equity	1,669,557		1,613,733
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	3,942,614	$	3,619,760

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)	2014			2013			2012
Other income	$	786		$	1,487		$	2,165
General and administrative expense	(7,336		)	(56,707		)	(31,833		)
Interest expense	(105,411		)	(98,660		)	(90,289		)
Loss on extinguishment of debt	(29,205		)	—			—
Other expense	(196		)	(3,609		)	(812		)
LOSS BEFORE INCOME TAXES	(141,362		)	(157,489		)	(120,769		)
INCOME TAX BENEFIT	(55,646		)	(72,798		)	(49,141		)
LOSS AFTER TAXES	(85,716		)	(84,691		)	(71,628		)
EQUITY IN SUBSIDIARIES’ NET EARNINGS	329,799			318,197			259,504
NET INCOME	$	244,083		$	233,506		$	187,876

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)	2014			2013		2012
NET INCOME	$	244,083		$	233,506	$	187,876
OTHER COMPREHENSIVE (LOSS) INCOME
Derivative instruments (net of tax of $1,897, $16,087 and $1,746 for the years ended December 31, 2014, 2013 and 2012, respectively)	(1,479		)	24,304		(2,680		)
Available-for-sale securities (net of tax of $18 and $46 for the years ended December 31, 2014 and 2013, respectively)	(32		)	71		—
TOTAL OTHER COMPREHENSIVE (LOSS) INCOME, NET OF TAX	(1,511		)	24,375		(2,680		)
TOTAL COMPREHENSIVE INCOME	$	242,572		$	257,881	$	185,196

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)	2014			2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	244,083		$	233,506		187,876
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in subsidiaries' earnings	(329,799		)	(318,197		)	(259,504		)
Dividends from subsidiaries	224,167			169,973			127,412
Deferred and other income taxes	(122,413		)	(117,956		)	(87,861		)
Loss on extinguishment of debt	29,205			—			—
Intercompany tax payments from subsidiaries	124,315			112,008			83,144
Share-based compensation expense	14,652			15,667			15,622
Other	2,852			(226		)	2,438
Changes in assets and liabilities, exclusive of changes shown separately:
Accounts receivable from subsidiaries	1,304			(979		)	(9,677		)
Prepaid and other current assets	4,154			16,948			(21,803		)
Accounts payable	(3,869		)	(2,294		)	2,680
Accrued payroll	1,572			1,190			2,727
Accrued interest	(2,671		)	6,501			93
Accrued taxes	11,147			(179		)	(122		)
Tax benefit on the excess tax deduction of share-based compensation	(7,767		)	(4,302		)	(23,022		)
Other current liabilities	(2,425		)	2,278			21,076
Other non-current assets and liabilities, net	3,078			12,465			(65		)
Net cash provided by operating activities	191,585			126,403			41,014
CASH FLOWS FROM INVESTING ACTIVITIES
Equity contributions to subsidiaries	(348,661		)	(339,770		)	(337,630		)
Return of capital from subsidiaries	126,900			96,120			91,399
Proceeds from sale of marketable securities	495			20,844			5,935
Purchases of marketable securities	(6,091		)	(22,250		)	(11,779		)
Other	(984		)	—			—
Net cash used in investing activities	(228,341		)	(245,056		)	(252,075		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	398,664			548,484			—
Borrowings under revolving credit agreement	533,900			222,800			295,450
Borrowings under term loan credit agreements	60,000			390,000			200,000
Retirement of long-term debt - including extinguishment of debt costs	(248,625		)	(267,000		)	—
Repayments of revolving credit agreement	(480,400		)	(252,400		)	(265,850		)
Repayments of term loan credit agreements	(39,000		)	(450,000		)	—
Issuance of common stock	20,713			10,042			14,189
Dividends on common and restricted stock	(95,595		)	(84,129		)	(75,153		)
Repurchase and retirement of common stock	(134,284		)	(4,885		)	(7,266		)
Tax benefit on the excess tax deduction of share-based compensation	7,767			4,302			23,022
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	(6,932		)	5,746			(25		)
Net cash provided by financing activities	16,208			122,960			184,367
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS	(20,548		)	4,307			(26,694		)
CASH AND CASH EQUIVALENTS — Beginning of period	26,853			22,546			49,240
CASH AND CASH EQUIVALENTS — End of period	$	6,305		$	26,853		$	22,546

Supplementary cash flows information:
Interest paid (net of interest capitalized)	$	105,817		$	90,224		$	88,303
Income taxes paid — net	44,524			20,092			41,174
Supplementary non-cash investing and financing activities:
Equity transfers to subsidiaries	6,227			6,213			6,470

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 and the proceeds raised from the sale of debt and equity securities. ITC Holdings may not be able to access cash generated by our subsidiaries in order to fulfill cash commitments or to 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, 2014 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 the Company's 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, 2014, the maturities of our debt outstanding were as follows:



(In thousands)
2015	$	—
2016	300,344
2017	50,000
2018	385,000
2019	53,500
2020 and thereafter	1,350,340
Total	$	2,139,184

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 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 $2,126.1 million and $1,864.7 million at December 31, 2014 and 2013, respectively. The total book value of the ITC Holdings Senior Notes, net of discount, was $1,920.7 million and $1,741.9 million at December 31, 2014 and 2013, respectively. At December 31, 2014, we had a total of $214.5 million outstanding under our revolving and term loan credit agreements, which is a variable rate loan. At December 31, 2013, we had a total of $140.0 million outstanding under our term loan credit agreement. No amount was outstanding under our revolving credit agreement at December 31, 2013. 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.

Covenants

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dividends. In addition, the covenants require us to meet certain financial ratios, such as maintaining certain debt to capitalization ratios. At December 31, 2014, we were not in violation of any debt covenant.

3. RELATED-PARTY TRANSACTIONS

During 2014, 2013 and 2012, we made equity contributions to our subsidiaries of $348.7 million, $339.8 million and $337.6 million, respectively. ITCTransmission, MTH, ITC Midwest and other subsidiaries paid cash dividends to ITC Holdings totaling $224.2 million, $170.0 million and $127.4 million in 2014, 2013 and 2012, respectively. ITCTransmission, MTH, ITC Midwest and other subsidiaries provided a return of capital to ITC Holdings totaling $126.9 million, $96.1 million and $91.4 million in 2014, 2013 and 2012, respectively.

Additionally, ITCTransmission paid $38.1 million, $39.1 million and $18.9 million to ITC Holdings under an intercompany tax sharing arrangement during 2014, 2013 and 2012, respectively. MTH paid $41.4 million, $30.0 million and $17.6 million to ITC Holdings under an intercompany tax sharing arrangement during 2014, 2013 and 2012, respectively. ITC Midwest paid $34.3 million, $33.6 million and $37.2 million to ITC Holdings under an intercompany tax sharing arrangement during 2014, 2013 and 2012, respectively. ITC Great Plains paid $10.6 million, $9.4 million and $4.3 million to ITC Holdings under an intercompany tax sharing arrangement during 2014, 2013 and 2012, respectively. The total tax payments received from subsidiaries pursuant to the intercompany tax sharing arrangements 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 26, 2015.



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 26, 2015
Joseph L. Welch	Executive Officer (principal executive officer)

/s/ REJJI P. HAYES	Senior Vice President, Chief	February 26, 2015
Rejji P. Hayes	Financial Officer and Treasurer (principal financial
	and accounting officer)

/s/ ALBERT ERNST	Director	February 26, 2015
Albert Ernst

/s/ CHRISTOPHER H. FRANKLIN	Director	February 26, 2015
Christopher H. Franklin

/s/ EDWARD G. JEPSEN	Director	February 26, 2015
Edward G. Jepsen

/s/ DAVE R. LOPEZ	Director	February 26, 2015
Dave R. Lopez

/s/ WILLIAM J. MUSELER	Director	February 26, 2015
William J. Museler

/s/ HAZEL R. O’LEARY	Director	February 26, 2015
Hazel R. O’Leary

/s/ THOMAS G. STEPHENS	Director	February 26, 2015
Thomas G. Stephens

/s/ GORDON BENNETT STEWART, III	Director	February 26, 2015
Gordon Bennett Stewart, III

/s/ LEE C. STEWART	Director	February 26, 2015
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

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

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)

4.4			First Supplemental Indenture, dated as of July 16, 2003, supplemental to the 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)

4.15			First Supplemental Indenture, dated as of December 10, 2003, supplemental 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 10-Q for the quarter ended September 30, 2006)

4.16			Second Supplemental Indenture, dated as of December 10, 2003, supplemental to the First Mortgage Indenture between Michigan Electric Transmission Company, LLC and JPMorgan Chase Bank, 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 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)

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Exhibit No.		Description of Exhibit



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

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

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

4.22			Fourth Supplemental Indenture, dated as of December 11, 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)

4.23			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)

108

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Exhibit No.		Description of Exhibit



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

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

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

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

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

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)

*10.13			Amended and Restated 2003 Stock Purchase and Option Plan for Key Employees of the Registrant and its Subsidiaries (filed with Registrant’s Registration Statement on Form S-1, as amended, Reg. No. 333-123657)

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

10.28			Service Level Agreement— Construction and Maintenance/Engineering/System Operations, dated February 28, 2003, between The Detroit Edison Company and International Transmission Company (filed with Registrant’s Registration Statement on Form S-1, as amended, Reg. No. 333-123657)

*10.34			Form of stock option agreement for executive officers under Amended and Restated 2003 Stock Purchase and Option Plan for Key Employees of the Registrant and its subsidiaries (filed with Registrant’s Form10-Q for the quarter ended September 30, 2005)

*10.38			Amendment No. 1 dated as of February 8, 2006, to Amended and Restated 2003 Stock Purchase and Option Plan for Key Employees of the Registrant (filed with Registrant’s Form 8-K filed on February 14, 2006)

*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)

*10.48			Summary of Stock Ownership Guidelines, effective August 16, 2006, for Registrant’s Directors and Executive Officers (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)

10.61			Form of Distribution-Transmission Interconnection Agreement, by and between ITC Midwest LLC, as Transmission Owner and Interstate Power and Light Company, as Local Distribution Company, dated as of December 17, 2007 (filed with Registrant’s Form 8-K filed on December 21, 2007)

*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)

*10.71			Form of Amendment to Stock Option Agreement under 2003 Plan (Initial Option) (August 2008) (filed with Registrant’s Form 8-K filed on August 19, 2008)

109

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Exhibit No.		Description of Exhibit



*10.72			Form of Amendment to Stock Option Agreement under 2003 Plan (IPO Option) (August 2008) (filed with Registrant’s Form 8-K filed on August 19, 2008)

*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)

*10.79			Form of Restricted Stock Award Agreement for Non-employee Directors under Amended and Restated 2003 Stock Purchase and Option Plan for Key Employees of the Registrant and its subsidiaries (filed with Registrant’s 2008 Form 10-K)

*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)

10.10			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)

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

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

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

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

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

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

*10.113			Employment Agreement between ITC Holdings Corp. and Cameron M. Bready, dated as of December 21, 2012 (filed with Registrant's Form 8-K on January 23, 2013)

*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)

110

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Exhibit No.		Description of Exhibit




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)

*10.131			Summary of Annual Corporate Performance Bonus Plan for Executives as of February 2014 (filed with Registrant’s Form 10-Q for the quarter ended March 31, 2014)

10.132			Amended and Restated Generator Interconnection Agreement entered into by and among Midcontinent Independent System Operator, Inc., Michigan Electric Transmission Company, LLC and Consumers Energy Company, effective May 2, 2014 (filed with Registrant’s Form 10-Q for quarter ended June 30, 3014)

*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, 3014)

*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, 3014)

*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, 3014)

*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, 3014)

*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, 3014)

*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, 3014)

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

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

111

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Exhibit No.		Description of Exhibit



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.

112

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