10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

þ	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended December 31, 2013

OR

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number: 001-32576

ITC HOLDINGS CORP.

(Exact Name of Registrant as Specified in Its Charter)

Michigan (State or Other Jurisdiction of Incorporation or Organization) 32-0058047 (I.R.S. Employer Identification No.)

27175 Energy Way

Novi, Michigan 48377

(Address Of Principal Executive Offices, Including Zip Code)

(248) 946-3000

(Registrant’s Telephone Number, Including Area Code)

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class Common stock, without par value Name of Each Exchange on Which Registered New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act of 1933. YesþNo 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 oNoþ

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. Yesþ 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 þNo o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information, statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer þ	Accelerated filer o	Non-accelerated filero	Smaller Reporting Company o
		(Do not check if a smaller reporting company)

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o Noþ

The aggregate market value of the registrant’s common stock held by non-affiliates on June 30, 2013 was approximately $4.7 billion, based on the closing sale price as reported on the New York Stock Exchange. For purposes of this computation, all executive officers, directors and 10% beneficial owners of the registrant are assumed to be affiliates. Such determination should not be deemed an admission that such officers, directors and beneficial owners are, in fact, affiliates of the registrant.

The number of shares of the Registrant’s Common Stock, without par value, outstanding as of February 21, 2014 was 52,522,301.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Registrant’s definitive Proxy Statement for the Registrant’s 2014 Annual Meeting of Shareholders (the “Proxy Statement”) filed pursuant to Regulation 14A are incorporated by reference in Part III of this Form 10-K.

ITC Holdings Corp.

Form 10-K for the Fiscal Year Ended December 31, 2013

INDEX

		Page
PART I		5
Item 1.	Business	5
Item 1A.	Risk Factors	16
Item 1B.	Unresolved Staff Comments	23
Item 2.	Properties	23
Item 3.	Legal Proceedings	25
Item 4.	Mine Safety Disclosures	25
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	50
Item 8.	Financial Statements and Supplementary Data	52
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	99
Item 9A.	Controls and Procedures	99
Item 9B.	Other Information	99
PART III		100
Item 10.	Directors, Executive Officers and Corporate Governance	100
Item 11.	Executive Compensation	100
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	100
Item 13.	Certain Relationships and Related Transactions, and Director Independence	100
Item 14.	Principal Accountant Fees and Services	100
PART IV		101
Item 15.	Exhibits and Financial Statement Schedules	101
Signatures		108
Exhibits		109

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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;

• “Green Power Express” are references to Green Power Express LP, an indirect 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 (formerly known as The Detroit Edison Company), a wholly-owned subsidiary of DTE Energy;

• “DTE Energy” are references to DTE Energy Company;

• “Entergy” are references to Entergy Corporation;

• “Entergy Transaction” are references to the transaction whereby the electric transmission business of Entergy 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);

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• “LIBOR” are references to the London Interbank Offered Rate;

• “MISO” are references to the Midcontinent Independent System Operator, Inc. (formerly known as the Midwest Independent Transmission System Operator, Inc.), a FERC-approved RTO which oversees the operation of the bulk power transmission system for a substantial portion of the Midwestern United States and Manitoba, Canada, and of which ITCTransmission, METC and ITC Midwest are members;

• “MOPSC” are references to the Missouri Public Service Commission;

• “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;

• “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

Unless otherwise noted, the share and per share data in this annual report on Form 10-K do not reflect the three-for-one stock split effective February 28, 2014 to shareholders of record on February 18, 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 after acquiring certain electric transmission assets in Kansas. 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.

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. On December 13, 2013, ITC Holdings and Entergy mutually agreed to terminate the Entergy Transaction. For further details, refer to “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Project Updates and Other Recent Developments.”

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 $4.2 billion for the period 2012 through 2016 of which $1.7 billion has been invested through December 31, 2013. Refer to the discussion of risks associated with our strategic development opportunities in “Item 1A Risk Factors — Our Regulated Operating Subsidiaries’ actual capital expenditures may be lower than planned, which would decrease 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.”

Current Transmission Systems

We expect to invest approximately $1.6 billion from 2012 through 2016 at our Regulated Operating Subsidiaries in order to maintain and replace the current transmission infrastructure, enhance system integrity and reliability and accommodate load growth.

Network Upgrades to Support Generator Interconnections

We expect to invest approximately $0.9 billion from 2012 through 2016 to develop and build transmission infrastructure to support generator interconnections.

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Included in this amount is the Thumb Loop Project located in ITCTransmission’s region, which 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. In September 2013, Phase 1 of the Thumb Loop Project, consisting of 62 miles of 345 kV transmission facilities, was placed into service. 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, 2013, ITCTransmission has invested $315.1 million in the Thumb Loop Project.

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 $1.7 billion from 2012 through 2016 to construct various development projects, or portions thereof, that we are currently advancing in the South Central and North Central regions of the country. We are pursuing strategic development opportunities for transmission investments related to upgrading 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.

South Central Region

The Kansas V-Plan Project, which consists of a transmission line running from the Spearville substation to Medicine Lodge, Kansas, is currently under construction. Through December 31, 2013, ITC Great Plains has invested $179.1 million in the Kansas V-Plan project. We estimate that ITC Great Plains will invest a total of approximately $300 million in its portion of the project, which is currently anticipated to be completed at the end of 2014.

North Central Region

In 2009, we identified a significant regional transmission project, known as the Green Power Express Project, which consisted of transmission line segments that would facilitate the movement of power from the Dakotas, Minnesota and Iowa to Midwest load centers that demand energy. Several transmission projects that address transmission needs that are similar to various segments of the Green Power Express Project have been approved through the MISO planning process. In December 2011, MISO approved the first portfolio of Multi-Value Projects (“MVPs”) identified through MISO’s Regional Generation Outlet Study (“RGOS”), which includes portions of four MVPs that we will build, own and operate. These four MVPs are located in south central Minnesota, northern and southeast Iowa, southwest Wisconsin, and northeast Missouri.

We continue to explore other opportunities to advance regional transmission projects, including other segments of the Green Power Express Project, through the MISO MVP process.

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;

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• 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”), 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

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remain in effect until terminated by mutual agreement of the parties (subject to any required FERC approvals) unless earlier terminated pursuant to its terms. The MOA identifies the control area coordination services that ITCTransmission is obligated to provide to DTE Electric. The MOA also requires DTE Electric to provide certain generation-based support services to ITCTransmission.

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

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

METC

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

Amended and Restated Easement Agreement. Under the Amended and Restated Easement Agreement (the “Easement Agreement”), dated as of April 29, 2002 and as further supplemented, Consumers Energy provides METC with an easement to the land, which we refer to as premises, on which a majority of METC’s transmission towers, poles, lines and other transmission facilities used to transmit electricity at voltages of at least 120 kV are located, which we refer to collectively as the facilities. Consumers Energy retained for itself 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

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for payment by METC prior to removing or relocating these facilities, and Consumers Energy need not commence any relocation work until an alternative right-of-way satisfactory to Consumers Energy is obtained at METC’s expense.

The term of the Easement Agreement runs through December 31, 2050 and is subject to 10 automatic 50-year renewals after that time unless METC provides one year’s notice of its election not to renew the term. Consumers Energy may terminate the Easement Agreement 30 days after giving notice of a failure by METC to pay its quarterly installment if METC does not cure the non-payment within the 30-day notice period. At the end of the term or upon any earlier termination of the Easement Agreement, the easement and related rights terminate and the transmission facilities revert to Consumers Energy.

Amended and Restated Operating Agreement. Under the Amended and Restated Operating Agreement (the “Operating Agreement”), dated as of April 29, 2002, METC agrees to operate its transmission system to provide all transmission customers with safe, efficient, reliable and nondiscriminatory transmission service pursuant to its tariff. Among other things, METC is responsible under the Operating Agreement for maintaining and operating its transmission system, providing Consumers Energy with information and access to its transmission system and related books and records, administering and performing the duties of control area operator (that is, the entity exercising operational control over the transmission system) and, if requested by Consumers Energy, building connection facilities necessary to permit interaction with new distribution facilities built by Consumers Energy. Consumers Energy has corresponding obligations to provide METC with access to its books and records and to build distribution facilities necessary to provide adequate and reliable transmission services to wholesale customers. Consumers Energy must cooperate with METC as METC performs its duties as control area operator, including by providing reactive supply and voltage control from generation sources or other ancillary services and reducing load. The Operating Agreement is effective through 2050 and is subject to 10 automatic 50-year renewals after that time, unless METC provides one year’s notice of its election not to renew.

Amended and Restated Purchase and Sale Agreement for Ancillary Services. The Amended and Restated Purchase and Sale Agreement for Ancillary Services (the “Ancillary Services Agreement”) is dated as of April 29, 2002. Since METC does not own any generating facilities, it must procure ancillary services from third party suppliers, such as Consumers Energy. Currently, under the Ancillary Services Agreement, METC pays 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 most recently 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 most recently effective as of July 4, 2013, 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.

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ITC Midwest

IP&L operates the electric distribution system to which ITC Midwest’s transmission system connects. ITC Midwest is a party to a number of operating contracts with IP&L that govern the operations and maintenance of its transmission system. These contracts include the following:

Distribution-Transmission Interconnection Agreement. The 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 most recently effective as of August 6, 2013, in order to establish, re-establish and maintain the direct electricity interconnection of IP&L’s electricity generating assets with ITC Midwest’s transmission system for the purposes of transmitting electric power from and to the electricity generating facilities. The LGIA will remain in effect until terminated by ITC Midwest or until IP&L elects to terminate the agreement if a particular unit ceases commercial operation for three consecutive years.

Operations Services Agreement For 34.5 kV Transmission Facilities. ITC Midwest and IP&L entered into the Operations Services Agreement for 34.5 kV Transmission Facilities (the “OSA”), effective as of January 1, 2011, under which IP&L performs certain operations functions for ITC Midwest’s 34.5 kV transmission system on behalf of ITC Midwest. The OSA provides that when ITC Midwest upgrades 34.5 kV facilities to higher operating voltages it may notify IP&L of the change and the OSA is no longer applicable to those facilities. The OSA will remain in full force and effect until December 31, 2015 and will extend automatically from year to year thereafter until terminated by either party upon not less than one year prior written notice to the other party.

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 the ITC Great Plains Elm Creek and Flat Ridge Substations, which ITC Great Plains purchased from Mid-Kansas. Also, Mid-Kansas performs field operations and maintenance for ITC Great Plains for the ITC Great Plains assets at Spearville Substation, and for ITC Great Plains’ Spearville - Post Rock and Post Rock - Axtell 345 kV assets. 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 have entered into a maintenance agreement (the “Midwest Energy Agreement”) dated as of June 25, 2012. Pursuant to which Midwest Energy has agreed to perform various field operations and maintenance service related to ITC Great Plains facilities. The Midwest Energy Agreement has 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. Services must continue to be provided for at least six months subsequent to the termination date in any case.

Regulatory Environment

Many regulators and public policy makers support the need for further investment in the transmission grid. The growth 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

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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, 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 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 adoption of certain reliability standards by transmission owners and may take enforcement actions for violators, including fines of up to $1.0 million per day. The NERC was assigned the responsibility of developing and enforcing these mandatory reliability standards. We continually assess our transmission systems against standards established by the NERC, as well as the standards of applicable regional entities under the 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 holding companies in certain circumstances.

Federal Regulation

As electric transmission companies, our Regulated Operating Subsidiaries are regulated by the FERC. The FERC is an independent regulatory commission within the DOE that regulates the interstate transmission and certain wholesale sales of natural gas, the transmission of oil and oil products by pipeline and the transmission and wholesale 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.

In 2011, the FERC issued Order No. 1000 (“Order 1000”) which amends certain existing transmission planning and cost allocation requirements to ensure that FERC-jurisdictional services are provided at just and reasonable rates and on a basis that is just and reasonable and not unduly discriminatory or preferential. With respect to transmission planning, Order 1000: (1) requires that each public utility transmission provider participate in a regional

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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. Some of the new provisions that were filed have already 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.

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 tariff. 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 Attachment FF of 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 Electric Transmission Authority (“KETA”) Project, which was part of the balanced portfolio of projects approved by SPP, and the Kansas V-Plan Project, which is subject to SPP’s highway/byway cost allocation. 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.”

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, pursuant to Michigan Public Acts 197 and 198 of 2004, 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

Iowa Code chapter 478 provides that 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 Code chapter 478 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 Code chapter 364, 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.

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ITC Midwest also is subject to the regulatory oversight of certain state agencies (including the Iowa Department of Natural Resources) and certain local authorities with respect to the issuance of environmental, highway, railroad and similar permits.

Minnesota

The MPUC has jurisdiction over the construction, siting and routing of new transmission lines or upgrades of existing lines through Minnesota’s Certificate of Need and Route Permit Processes. Transmission companies are also required to participate in the State’s Biennial Transmission Planning Process and are subject to the state’s preventative maintenance requirements. Pursuant to Minnesota law, ITC Midwest has the right as an independent transmission company to condemn property in the State of Minnesota for the purpose of building new transmission facilities.

ITC Midwest is also subject to the regulatory oversight of the Minnesota Pollution Control Agency, the Minnesota Department of Natural Resources, the MPUC in conjunction with the Department of Commerce and certain local authorities for compliance with applicable environmental standards and regulations.

Illinois

The ICC exercises jurisdiction over siting of new transmission lines through its requirements for Certificates of Public Convenience and Necessity and Right-Of-Way acquisition that apply to construction of new or upgraded facilities.

ITC Midwest also is subject to the regulatory oversight of the Illinois Environmental Protection Agency, the Illinois Department of Natural Resources, the Illinois Pollution Control Board and certain local authorities for compliance with all environmental standards and regulations.

Missouri

Because ITC Midwest is a “public utility” and an “electrical corporation” under Missouri law, the MOPSC has jurisdiction to determine whether ITC Midwest may operate in such capacity. The MOPSC also exercises jurisdiction with regard to other non-rate matters affecting this Missouri asset such as transmission substation construction, general safety and the transfer of the franchise or property.

ITC Midwest is also subject to the regulatory oversight of the Missouri Department of Natural Resources for compliance with all environmental standards and regulations relating to this transmission line.

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.

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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 23.8%, 24.0% and 27.9%, respectively, of our consolidated billed revenues for the year ended December 31, 2013. 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 2011 revenue accruals and deferrals and exclude any amounts for the 2013 revenue accruals and deferrals that were included in our 2013 operating revenues, but will not be billed to our customers until 2015. 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 collection for the 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 is the only transmission system in its respective service area and, therefore, effectively has no competitors. However, the competitive environment may change 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 regulatory 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.

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Employees

As of December 31, 2013, we had 539 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 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.

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Our Code of Business Conduct and Ethics applies to all directors, officers and employees, including our Chairman, President and Chief Executive Officer and our Executive Vice President and Chief Financial Officer. We will post any amendments to the Code of Business Conduct and Ethics, and any waivers that are required to be disclosed by the rules of either the SEC or the 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.

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. We have also made certain commitments to federal and state regulators with respect to, among other things, our rates in connection with acquisitions that could have a material 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.

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%, reducing the targeted equity component of our capital structure from 60% to 50% and terminating the return on equity adders currently approved for ITCTransmission and METC. In the event a refund is required upon resolution of the complaint, the joint complainants are seeking a refund effective date as of November 12, 2013. An unfavorable resolution of this 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.

In the Minnesota regulatory proceeding to approve ITC Midwest’s December 2007 acquisition of the transmission assets of IP&L, ITC Midwest agreed to build two transmission projects intended to improve the reliability and efficiency of our electric transmission system. Specifically, ITC Midwest made commitments to use commercially reasonable best efforts to complete these projects prior to December 31, 2009 and 2011, respectively. In the event ITC Midwest is found to have failed to meet these commitments, the allowed 12.38% rate of return on the actual equity portion of ITC Midwest’s capital structure would be reduced to 10.39% until such time as ITC Midwest completes these projects, and ITC Midwest would refund with interest any amounts collected since the closing

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date of the transaction that exceeded what would have been collected if the 10.39% return on equity had been used. The project that was required to be completed prior to December 31, 2009 was completed by that deadline. With respect to the second project, the 345 kV Salem-Hazleton line, certain regulatory approvals were needed from the IUB before construction of the project could commence, but due to the IUB’s case schedule, these approvals were not received until the second quarter of 2011. As a result of the delay in the receipt of the necessary regulatory approvals, the project was not completed by December 31, 2011. We have notified the Minnesota Public Utilities Commission that the Salem-Hazleton line was placed into service on April 25, 2013, and requested confirmation from the commission that ITC Midwest has satisfied its commitment and that no refund is due as a result of the project not being completed by December 31, 2011. We believe we used commercially reasonable best efforts to meet the December 31, 2011 deadline.

Any of the events described above could have an adverse effect on our business, financial condition, results of operations and cash flows.

Our Regulated Operating Subsidiaries’ actual capital expenditures may be lower than planned, which would decrease 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.

Each of our Regulated 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 which include estimated transmission network upgrades for generator interconnections. The amounts for network upgrades could change significantly due to factors beyond our control, such as changes in the MISO queue for generation projects and whether the generator meets the various criteria of Attachment FF of the MISO Open Access Transmission, Energy, and Operating Reserve Markets Tariff for the project to qualify as a refundable network upgrade, among other factors. If our Regulated Operating Subsidiaries’ capital investment and the resulting in-service property, plant and equipment are lower than anticipated for any reason, our Regulated Operating Subsidiaries will have a lower than anticipated rate base thus causing their revenue requirements and future earnings to be potentially lower than anticipated.

In addition, we are pursuing broader strategic development investment opportunities for transmission construction related to building regional transmission facilities, interconnections for generating resources and other investment opportunities. The incumbent utilities or other entities with transmission development initiatives may compete with us by deciding to pursue capital projects that we are pursuing. These estimates of potential investment opportunities are based primarily on foreseeable transmission needs and general transmission construction costs, not necessarily on particular project cost estimates.

Any capital investment at our Regulated Operating Subsidiaries or as a result of our broader strategic development initiatives may be lower than expected 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 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 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 Regulated Operating Subsidiaries or as a result of the broader strategic development initiatives.

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 may also be required to acquire securities in a public utility. Section 203 of the FPA also provides the FERC with

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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 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 federal 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 shift 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.

If amounts billed for transmission service for our Regulated Operating Subsidiaries’ transmission systems are lower than expected, or our actual revenue requirements are higher than expected, the timing of collection of our revenues would be delayed.

If amounts billed for transmission service are lower than expected, which could result from lower network load or point-to-point transmission service on our Regulated Operating Subsidiaries’ transmission systems due to a weak economy, changes in the nature or composition of the transmission assets of our Regulated Operating Subsidiaries and surrounding areas, poor transmission quality of neighboring transmission systems, or for any other reason, the timing of the collection of our revenue requirement would likely be delayed until such circumstances are adjusted through the true-up mechanism in our Regulated Operating Subsidiaries’ formula rate templates. In addition, if the revenue requirements of our Regulated Operating Subsidiaries are higher than expected, due to higher actual expenditures compared to the forecasted expenditures used to develop their billing rates or for any 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 72.2% of ITCTransmission’s total billed revenues for the year ended December 31, 2013 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 75.6% of METC’s total billed revenues for the year ended December 31, 2013 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 79.1% of ITC Midwest’s total billed revenues for the year ended December 31, 2013 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

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2011 revenue accruals and deferrals and exclude any amounts for the 2013 revenue accruals and deferrals that were included in our 2013 operating revenues, but will not be billed to our customers until 2015.

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 Regulated Operating Subsidiaries’ assets are located is subject to easements, mineral rights and other similar encumbrances. As a result, our Regulated Operating Subsidiaries 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 ITCTransmission’s, ITC Midwest’s and ITC Great Plains’ 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.

Our Regulated Operating Subsidiaries contract with third parties to provide services for certain aspects of their businesses. If any of these agreements are terminated, our Regulated Operating Subsidiaries may face a shortage of labor or replacement contractors to provide the services formerly provided by these third parties.

Our Regulated Operating Subsidiaries enter into various agreements and arrangements with third parties to provide services for the operation of certain aspects of their businesses, which, if terminated could result in a shortage of a readily available workforce to provide these services. For example, ITC Midwest and IP&L have entered into the Operations Services Agreement For 34.5 kV Transmission Facilities (the “OSA”), under which IP&L performs certain operations functions for ITC Midwest’s 34.5 kV transmission system. The OSA’s term is from January 1, 2011 until December 31, 2015, and by its terms will remain in full force and effect from year to year thereafter until terminated by either party upon not less than one year’s prior written notice to the other party. If the OSA is terminated for any reason, we may face difficulty finding a qualified replacement work force to provide such services, which could have an adverse effect on our ability to carry on our business and on our results of operations.

Hazards associated with high-voltage electricity transmission may result in suspension of our Regulated Operating Subsidiaries’ operations or the imposition of civil or criminal penalties.

The operations of our Regulated Operating Subsidiaries 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.

Our Regulated Operating Subsidiaries are subject to environmental regulations and to laws that can give rise to substantial liabilities from environmental contamination.

The operations of our Regulated Operating Subsidiaries 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

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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. Environmental requirements generally have become more stringent in recent years, and compliance with those requirements more expensive.

Our Regulated Operating Subsidiaries 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 Regulated Operating Subsidiaries’ assets and operations also involve the use of materials classified as hazardous, toxic, or otherwise dangerous. Some of our Regulated Operating Subsidiaries’ 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 our Regulated Operating Subsidiaries 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.

Our Regulated Operating Subsidiaries 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 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 Regulated Operating 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.

The Regulated Operating 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.

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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 Regulated Operating Subsidiaries’ transmission facilities and DTE Electric’s, Consumers Energy’s and IP&L’s generation and distribution facilities, 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 Regulated Operating Subsidiaries and our other 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 Regulated Operating Subsidiaries and our other subsidiaries, the proceeds raised from the sale of our debt and equity securities and borrowings under our various credit agreements. Each of our Regulated Operating Subsidiaries, however, is legally distinct from us and has no obligation, contingent or otherwise, to make funds available to us for the payment of dividends to ITC Holdings’ shareholders or otherwise. The ability of each of our Regulated Operating Subsidiaries and our other subsidiaries to pay dividends and make other payments to us is subject to, among other things, the availability of funds, after taking into account capital expenditure requirements, the terms of its indebtedness, applicable state laws and regulations of the FERC and the FPA. Our Regulated Operating Subsidiaries target a FERC-approved capital structure of 60% equity and 40% debt that may limit the ability of our Regulated Operating Subsidiaries to use net assets for the payment of dividends to ITC Holdings. While we currently intend to continue to pay quarterly dividends on our common stock, we have no obligation to do so. The payment of dividends is within the absolute discretion of our board of directors and will depend on, among other things, our results of operations, working capital requirements, capital expenditure requirements, financial condition, contractual restrictions, anticipated cash needs and other factors that our board of directors deems relevant.

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

We have a considerable amount of debt and our consolidated indebtedness includes various debt securities and borrowings which utilize 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 Regulated Operating Subsidiaries will be dedicated to the payment of interest on our indebtedness, thereby

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reducing the funds available for working capital, capital expenditures and the payment of dividends on our common stock.

• In the event that we are liquidated, 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 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.

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.

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

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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.

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 18,200 transmission towers and poles;

• station assets, such as transformers and circuit breakers, at 174 stations and substations which either interconnect ITCTransmission’s transmission facilities or connect ITCTransmission’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;

• 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 98 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 267 stations and substations which either interconnect ITC Midwest’s transmission facilities or connect ITC Midwest’s facilities with generation or distribution facilities owned by others;

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

• warehouses and related equipment; and

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

ITC Midwest’s First Mortgage Bonds are issued under ITC Midwest’s First Mortgage and Deed of Trust. As a result, the bondholders have the benefit of a first mortgage lien on substantially all of ITC Midwest’s property.

ITC Great Plains owns transmission and related assets including:

• approximately 190 miles of transmission lines rated at a voltage of 345 kV;

• approximately 1,171 transmission towers and poles;

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• station assets, such as transformers and circuit breakers, at 5 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.

As of December 31, 2013, there were no liens or encumbrances on the assets of ITC Great Plains.

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.

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 has traded on the NYSE since July 26, 2005 under the symbol “ITC”. Prior to that time, there was no public market for our stock. As of February 21, 2014, there were approximately 703 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 2013 and 2012, as reported on the NYSE and the cash dividends per share paid during the periods indicated.

Year Ended December 31, 2013	High	Low	Dividends
Quarter ended December 31, 2013	$106.74	$89.77	$0.4250
Quarter ended September 30, 2013	$99.33	$85.80	$0.4250
Quarter ended June 30, 2013	$93.69	$84.72	$0.3775
Quarter ended March 31, 2013	$89.40	$76.61	$0.3775
Year Ended December 31, 2012	High	Low	Dividends
Quarter ended December 31, 2012	$79.75	$74.28	$0.3775
Quarter ended September 30, 2012	$75.87	$69.10	$0.3775
Quarter ended June 30, 2012	$78.86	$66.30	$0.3525
Quarter ended March 31, 2012	$78.51	$71.65	$0.3525

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

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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 revolving and term loan credit facilities. 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.

If and when ITC Holdings pays a dividend on its common stock, pursuant to our special bonus plans for executives and certain non-executive employees, amounts equivalent to the dividend may be paid to the special bonus plan participants, if approved by the compensation committee. We currently expect these amounts to be paid upon the declaration of dividends on ITC Holdings’ common stock.

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 will be distributed on February 28, 2014, to the shareholders of record on February 18, 2014. See further discussion in Note 20 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.

Stock Repurchases

The following table sets forth, the repurchases of common stock for the quarter ended December 31, 2013:

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 (2)
October 2013	721	$	96.59	—	—
November 2013	1,076	99.49		—	—
December 2013	2,255	88.51		—	—
Total	4,052	$	93.22	—	—

____________________________

(1) Shares acquired were delivered to us by employees as payment of tax withholding obligations due to us upon the vesting of restricted stock.

(2) As of December 31, 2013, we did not have a publicly announced share repurchase plan.

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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)	2013			2012			2011			2010			2009
OPERATING REVENUES (a)	$	941,272		$	830,535		$	757,397		$	696,843		$	621,015
OPERATING EXPENSES
Operation and maintenance (b)	112,821			121,941			129,288			126,528			95,730
General and administrative (c) (d)	149,109			112,091			82,790			78,120			69,231
Depreciation and amortization (e)	118,596			106,512			94,981			86,976			85,949
Taxes other than income taxes	65,824			59,701			53,430			48,195			43,905
Other operating (income) and expense — net	(1,139		)	(769		)	(844		)	(297		)	(667		)
Total operating expenses	445,211			399,476			359,645			339,522			294,148
OPERATING INCOME	496,061			431,059			397,752			357,321			326,867
OTHER EXPENSES (INCOME)
Interest expense	168,319			155,734			146,936			142,553			130,209
Allowance for equity funds used during construction	(30,159		)	(23,000		)	(16,699		)	(13,412		)	(13,203		)
Loss on extinguishment of debt	—			—			—			—			1,263
Other income	(1,038		)	(2,401		)	(2,881		)	(2,340		)	(2,792		)
Other expense	6,571			4,218			3,962			2,588			2,918
Total other expenses (income)	143,693			134,551			131,318			129,389			118,395
INCOME BEFORE INCOME TAXES	352,368			296,508			266,434			227,932			208,472
INCOME TAX PROVISION	118,862			108,632			94,749			82,254			77,572
NET INCOME	$	233,506		$	187,876		$	171,685		$	145,678		$	130,900
Basic earnings per share (f)	$	4.46		$	3.65		$	3.36		$	2.89		$	2.62
Diluted earnings per share (f)	$	4.42		$	3.60		$	3.31		$	2.84		$	2.58
Dividends declared per share (f)	$	1.605		$	1.460		$	1.375		$	1.310		$	1.250

	ITC Holdings and Subsidiaries
	As of December 31,
(In thousands)	2013			2012			2011			2010		2009
BALANCE SHEET DATA:
Cash and cash equivalents	$	34,275		$	26,187		$	58,344		$	95,109	$	74,853
Working capital (deficit)	(307,841		)	(805,085		)	(113,939		)	69,338		147,335
Property, plant and equipment — net	4,846,526			4,134,579			3,415,823			2,872,277		2,542,064
Goodwill	950,163			950,163			950,163			950,163		950,163
Total assets	6,282,243			5,564,809			4,823,366			4,307,873		4,029,716
Debt:
ITC Holdings	1,881,918			1,689,619			1,459,599			1,459,178		1,458,757
Regulated Operating Subsidiaries	1,730,194			1,457,608			1,185,423			1,037,718		975,641
Total debt	3,612,112			3,147,227			2,645,022			2,496,896		2,434,398
Total stockholders’ equity	$	1,613,732		$	1,414,855		$	1,258,892		$	1,117,433	$	1,011,523

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	ITC Holdings and Subsidiaries
	Year Ended December 31,
(In thousands)	2013		2012		2011		2010		2009
CASH FLOWS DATA:
Capital expenditures	$	821,588	$	802,763	$	556,931	$	388,401	$	404,514

____________________________

(a) During 2012, we initially recognized the FERC audit refund liability, which resulted in a reduction in operating revenues of $11.0 million.

(b) The increase in operation and maintenance expenses in 2010 compared to 2009 were due, in part, to efforts in 2009 to mitigate operation and maintenance expenses to offset the impact of lower network load on cash flows and any potential revenue accrual relating to 2009.

(c) During 2011 and 2009, we recognized $2.1 million and $10.0 million, respectively of regulatory assets associated with the development activities of ITC Great Plains as well as certain pre-construction costs for the Kansas V-Plan and KETA projects. Upon initial establishment of these regulatory assets in 2011 and 2009, $2.1 million and $8.0 million, respectively, of general and administrative expenses were reversed of which $1.4 million and $5.9 million were incurred in periods prior to 2011 and 2009, respectively. No initial establishment of regulatory assets occurred in 2010 that resulted in reversal of expenses.

(d) During 2013, 2012 and 2011, we expensed external legal, advisory and financial services fees of $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.

(e) In 2010, the FERC accepted a depreciation study filed by ITC Midwest which revised its depreciation rates and the corresponding depreciation expense in 2010. These changes in accounting estimates resulted in lower composite depreciation rates primarily due to the revision of asset service lives and cost of removal values.

(f) Per share data does not reflect the impact of the three-for-one stock split, which will be effective on February 28, 2014 as discussed in Note 20 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.

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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.

As electric transmission utilities with rates regulated by the FERC, our Regulated Operating Subsidiaries earn revenues through tariff rates charged for the use of their electric transmission systems by our customers, which include investor-owned utilities, municipalities, cooperatives, power marketers and alternative energy suppliers. As independent transmission companies, our Regulated Operating Subsidiaries are subject to rate regulation only by the FERC. The rates charged by our Regulated Operating Subsidiaries are established using cost-based formula rate templates, as discussed in “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cost-Based Formula Rates with True-Up Mechanism.”

Our Regulated Operating Subsidiaries’ primary operating responsibilities include maintaining, improving and expanding their transmission systems to meet their customers’ ongoing needs, scheduling outages on system elements to allow for maintenance and construction, maintaining appropriate system voltages and monitoring flows over transmission lines and other facilities to ensure physical limits are not exceeded.

We derive nearly all of our revenues from providing electric transmission service over our Regulated Operating Subsidiaries’ transmission systems to investor-owned utilities such as DTE Electric, Consumers Energy and IP&L, and 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, 2013 or may affect future results include:

• Our capital investment of $844.5 million at our Regulated Operating Subsidiaries ($220.0 million, $176.9 million, $301.9 million and $145.7 million at ITCTransmission, METC, ITC Midwest and ITC Great Plains, respectively) for the year ended December 31, 2013, 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 2013 and 2012 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;

• Activities related to the Entergy Transaction, which was terminated in December 2013, for which we expensed external legal, advisory and financial services fees in 2013, 2012 and 2011 as discussed in Note 17 to the consolidated financial statements. The external and internal costs related to the Entergy Transaction were not included as components of revenue requirement as they were incurred at ITC Holdings. Any remaining expenses relating the Entergy Transaction are not expected to be material in 2014; and

• The rate of return on equity and capital structure complaint filed against all MISO Transmission Owners including our MISO Regulated Operating Subsidiaries as described in Note 4 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.

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Cost-Based Formula Rates with True-Up Mechanism

Our Regulated Operating Subsidiaries calculate their revenue requirements using cost-based formula rate templates and are effective without the need to file rate cases with the FERC, although the rates are subject to legal challenge at the FERC. Under 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 utilize forecasted expenses, property, plant and equipment, point-to-point revenues, network load at our MISO Regulated Operating Subsidiaries and other items for the upcoming calendar year to establish projected revenue requirements for each of our Regulated Operating Subsidiaries that are used as the basis for billing for service on their systems from January 1 to December 31 of that year. Our cost-based formula rate templates include a true-up mechanism, whereby our Regulated Operating Subsidiaries compare their actual revenue requirements to their billed revenues for each year to determine any over- or under-collection of revenue. The over- or under-collection typically results from differences between the projected revenue requirement used as the basis for billing and actual revenue requirement at each of our Regulated Operating Subsidiaries, or from differences between actual and projected monthly peak loads at our MISO Regulated Operating Subsidiaries. In the event billed revenues in a given year are more or less than actual revenue requirements, which are calculated primarily using information from that year’s FERC Form No. 1, our Regulated Operating Subsidiaries will refund or collect additional revenues, with interest, within a two-year period such that customers pay only the amounts that correspond to actual revenue requirements for that given period. This annual true-up ensures that our Regulated Operating Subsidiaries recover their allowed costs and earn their allowed returns.

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. For example, to the extent that amounts billed are less than the revenue requirement for a reporting period, a revenue accrual is recorded for the difference. To the extent that amounts billed are more than the revenue requirement for a reporting period, a revenue deferral is recorded for the difference. 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.

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The following table sets forth the monthly peak loads during the last three calendar years.

Monthly Peak Load (in MW) (a)

	2013			2012			2011
			ITC			ITC			ITC
	ITCTransmission	METC	Midwest	ITCTransmission	METC	Midwest	ITCTransmission	METC	Midwest
January	7,593	6,215	2,801	7,264	6,145	2,789	7,326	6,045	2,777
February	7,141	5,846	2,693	6,919	5,754	2,592	7,261	6,058	2,854
March	6,817	5,552	2,587	6,941	5,708	2,443	6,946	5,715	2,520
April	6,566	5,321	2,451	6,403	5,259	2,296	6,483	5,416	2,458
May	8,956	6,490	2,646	8,947	6,459	2,700	10,119	7,239	2,773
June	10,335	7,643	3,099	11,652	8,738	3,388	11,488	8,231	3,403
July	11,694	8,987	3,573	12,180	9,354	3,636	12,321	9,389	3,621
August	10,158	7,809	3,521	11,081	8,508	3,445	11,158	8,538	3,614
September	11,047	8,169	3,430	9,094	7,349	3,443	11,288	7,966	3,466
October	7,562	5,481	2,670	6,566	5,429	2,539	6,642	5,479	2,559
November	6,943	5,948	2,713	7,022	5,829	2,631	7,101	6,061	2,556
December	7,651	6,220	2,891	7,230	5,928	2,645	7,206	6,071	2,734
Total	102,463	79,681	35,075	101,299	80,460	34,547	105,339	82,208	35,335

____________________________

(a) Our MISO Regulated Operating Subsidiaries are each part of a joint rate zone. The load data presented is for all transmission owners in the respective joint rate zone and is used for billing network revenues. Each of our MISO Regulated Operating Subsidiaries makes up the most significant portion of the rates or revenue requirement billed to network load within their respective joint rate zone.

The following table presents the network transmission rates (per kW/month) for our MISO Regulated Operating Subsidiaries as posted by MISO that are relevant to our cash flows since January 1, 2011:

Network Transmission Rate	ITCTransmission	METC	ITC Midwest
January 1, 2011 to December 31, 2011	$2.495	$2.331	$6.694
January 1, 2012 to December 31, 2012	$2.188	$2.409	$6.797
January 1, 2013 to December 31, 2013	$2.147	$2.5263	$7.805
January 1, 2014 to December 31, 2014	$2.305	$2.781	$8.795

ITC Great Plains does not receive revenue based on a peak load or a dollar amount per kWeach 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.

Revenue Requirement Calculation

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 actual revenue requirements for a historic period is used to calculate the amount of network revenues recognized in that period and to calculate the true-up adjustment for that period. The calculation of projected revenue requirements is used to establish the transmission rate used for billing purposes, and follows the same methodology as the calculation of actual revenue requirement. The following steps illustrate the calculation of revenue requirement and the rate-setting methodology under the formula rate template with a true-up mechanism used by our MISO Regulated Operating Subsidiaries. ITC Great Plains follows a similar methodology and uses a FERC-approved return of 12.16% on the common equity portion of its capital structure.

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Step One — Establish Projected Rate Base and Calculate Projected Allowed Return

Rate base is projected using the average of the projected month-end balances for the months beginning with December 31 of the current year and ending with December 31 of the upcoming year and consists primarily of projected in-service property, plant and equipment, net of accumulated depreciation, as well as other items.

Projected rate base is multiplied by the projected weighted average cost of capital to determine the projected allowed return on rate base. The weighted average cost of capital is calculated using a projected 13-month average capital structure, the forecasted pre-tax cost of the debt portion of the capital structure and a FERC-approved return of 13.88%, 13.38% and 12.38% for ITCTransmission, METC and ITC Midwest, respectively, on the common equity portion of the capital structure.

Step Two — Calculate Projected Gross Revenue Requirement

The projected gross revenue requirement is calculated beginning with the projected allowed return on rate base, as calculated in Step One above, and adding projected recoverable operating expenses and an allowance for income taxes, depreciation and amortization.

Step Three — Calculate Projected Net Revenue Requirement

After calculating the projected gross revenue requirement in Step Two above, the 2014 projected gross revenue requirement is adjusted for any 2012 true-up adjustment and is reduced for certain revenues received other than network revenues, such as projected point-to-point, regional cost sharing revenues and rental revenues to arrive at our projected net revenue requirement.

Illustration of Formula Rate Setting

Set forth below is a simplified illustration of the calculation of ITCTransmission’s projected net revenue requirement as well as its component of the joint zone network transmission rate for billing purposes under its formula rate setting mechanism for the period from January 1, 2014 through December 31, 2014, that was based primarily upon projections of ITCTransmission’s 2014 FERC Form No. 1 data. Amounts below are approximations of the amounts used to establish ITCTransmission’s 2014 projected net revenue requirement.

Line	Item	Instructions	Amount
1	Projected rate base		$	1,379,630,000
2	Multiply by projected 13-month weighted average cost of capital (a)		10.297		%
3	Projected allowed return on rate base	(Line 1 x Line 2)	$	142,060,501
4	Projected recoverable operating expenses for 2014		$	61,666,000
5	Projected taxes and depreciation and amortization for 2014		$	167,751,000
6	Projected gross revenue requirements for 2014	(Line 3 + Line 4 + Line 5)	$	371,477,501
7	Less projected revenue credits for 2014		$	(112,971,000	)
8	Plus/(less) 2012 true-up adjustment		$	(21,346,000	)
9	Projected net revenue requirement for 2014	(Line 6 + Line 7 + Line 8)	$	237,160,501
10	Projected average monthly 2014 network load (in kW)		8,573,000
11	Annual component of the joint zone network transmission rate	(Line 9 divided by Line 10)	$	27.664
12	Monthly component of the joint zone network transmission rate ($/kW per month)	(Line 11 divided by 12 months)	$	2.305

____________________________

(a) The weighted average cost of capital for purposes of this illustration is calculated as follows:

			Weighted
	Percentage of		Average
	ITCTransmission’s		Cost of
	Total Capitalization	Cost of Capital	Capital
Debt	40.00%	4.92% (Pre-tax) =	1.969	%
Equity	60.00%	13.88% (After tax) =	8.328	%
	100.00%		10.297	%

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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 our anticipated capital investment in excess of depreciation as a result of our Regulated Operating Subsidiaries’ long-term capital investment programs to improve reliability, increase system capacity and upgrade the transmission network to support new generating resources. In addition, our capital investment efforts relating to development initiatives are based on establishing an ongoing pipeline of projects that will 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 adoption of certain reliability standards and may take enforcement actions against violators, including fines of up to $1.0 million per day. The NERC was assigned the responsibility of developing and enforcing these mandatory reliability standards. We continually assess our transmission systems against standards established by the NERC, as well as the standards of applicable regional entities under the 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		Actual Capital		Forecasted Capital
	Long-term Capital		Investment for the		Investment for the		Investment for the
	Investment Program		Year Ended		Years Ended December 31,		Year Ending
Source of Investment	2012-2016 (a)		December 31, 2013 (b)		2012 and 2013 (b)		December 31, 2014 (a)
(In millions)
ITCTransmission (c)	$	739	$	220.0	$	451.2	$250 — 285
METC	581		176.9		325.9		130 — 150
ITC Midwest	1,128		301.9		645.2		255 — 290
ITC Great Plains (d)	343		145.7		242.0		95 — 115
Development (e)	1,390		—		—		—
Total	$	4,181	$	844.5	$	1,664.3	$730 — 840

____________________________

(a) The forecasted investments in property, plant and equipment do not reflect any potential modifications resulting from the recently issued FERC order indicating that the use of Attachment FF for ITC Midwest was no longer just and reasonable as discussed in Note 4 to the consolidated financial statements under “Complaint of IP&L.” We do not anticipate a material impact on our long-term capital investment plan as a result of this order.

(b) 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.

(c) ITCTransmission’s investment program includes the Thumb Loop Project that is under construction.

(d) ITC Great Plains’ investment program includes the Kansas V-Plan Project that is under construction.

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(e) The long-term capital investment program includes expenditures to construct various development projects, including our portions of the four MISO MVPs as discussed under “Capital Project Updates and Other Recent Developments — North Central Region Development.” However, actual capital investments associated with our portions of the MISO MVPs are included in ITC Midwest’s actual capital investment through December 31, 2013 as ITC Midwest will construct, own and operate such 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, including the Attachment FF policy changes for ITC Midwest described in Note 4 to the consolidated financial statements under “Complaint of IP&L” 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, the generator’s potential failure to meet the various criteria of Attachment FF of the MISO tariff for the project to qualify as a refundable network upgrade, and other factors beyond our control.

Capital Project Updates and Other Recent Developments

Thumb Loop Project

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 the Michigan counties of Tuscola, Huron, Sanilac and St. Clair. Construction activities commenced for the Thumb Loop Project in 2012. In September 2013, Phase 1 of the Thumb Loop Project, consisting of 62 miles of 345 kV transmission facilities, was placed into service. Through December 31, 2013, ITCTransmission has invested $315.1 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 will run between Spearville and Wichita, Kansas. ITC Great Plains is 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 through December 31, 2013, ITC Great Plains has invested $179.1 million in the Kansas V-Plan Project. We estimate that ITC Great Plains will invest a total of approximately $300 million in its portion of the project, which is currently anticipated to be completed by the end of 2014.

Regulatory Assets

As of December 31, 2013, we have recorded approximately $13.9 million of regulatory assets for start-up, development and pre-construction expenses, including associated 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.

Development Bonuses

During 2013, 2012 and 2011, we recognized general and administrative expenses of $3.4 million, $2.9 million and $1.2 million, respectively, for bonuses for the successful completion of certain milestones relating to projects at ITC Great Plains. It is reasonably possible that future development-related bonuses would be authorized and awarded for these or other development projects.

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North Central Region Development

In 2009, we announced the Green Power Express project, which consisted of transmission line segments that would facilitate the movement of power from the Dakotas, Minnesota and Iowa to Midwest load centers that demand energy. After the announcement of the Green Power Express project, MISO undertook its Regional Generation Outlet Study (“RGOS”) to promote investments in new regional transmission infrastructure and implemented its Multi-Value Project cost allocation methodology. MISO’s RGOS and MVP processes provide a channel for segments of the Green Power Express project, to move forward through the planning approval process as MVPs. In December 2011, MISO approved the first portfolio of MVPs identified through the RGOS 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.

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.

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, 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%, reducing the targeted equity component of our capital structure from 60% to 50% and terminating the return on equity adders currently approved for ITCTransmission and METC. In the event a refund is required upon resolution of the complaint, the joint complainants are seeking a refund effective date as of November 12, 2013.

We believe that the return on equity along with adders and approved capital structure encourage transmission investment and offset the burdens associated with maintaining the independent transmission business model and RTO membership. ITCTransmission, METC and ITC Midwest recently filed responses that seek dismissal of the complaint for its failure to satisfy the requirements of the FERC’s Rule 206, or deny it on the merits, with prejudice, and we intend to vigorously defend the use of the current return on equity, the use of the current capital structures targeting 60% equity and defend continued use of the approved equity adders for RTO membership and independence.

As of December 31, 2013, the MISO Regulated Operating Subsidiaries had a total of approximately $2.4 billion of equity in their capital structures for ratemaking purposes. Based on this level of aggregate equity, we estimate that each 10 basis point reduction in the authorized base return on equity would reduce annual consolidated net income by approximately $2.4 million. We cannot at this time predict the ultimate outcome of this proceeding or the estimated impact on the MISO Regulated Operating Subsidiaries respective results of operations, cash flows and financial condition.

An unfavorable resolution of this complaint, however, could have a material impact on our future results of operations, cash flows and financial condition. For further details, see Note 4 of the consolidated financial statements.

Stock Split

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 will be distributed on February 28, 2014, to the shareholders of record on February 18, 2014. See further discussion in Note 20 to the consolidated financial statements.

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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 reservations on our transmission systems. Revenues for our transmission services take the form of network revenues, point-to-point revenues and regional cost sharing revenues. MISO and SPP are responsible for billing and collection of transmission services. 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 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, the KETA Project and Kansas V-Plan Project 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 costs sharing revenues are not subject to a direct true-up but instead are treated as reduction to either our regional or network gross revenue requirement when calculating net revenue requirement.

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 are subject to a true-up mechanism at our MISO Regulated Operating Subsidiaries that ensures that our MISO Regulated Operating Subsidiaries recover their allowed costs.

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Other Revenues consist of rental revenues, easement revenues, revenues relating to utilization of jointly owned lines under our transmission ownership and operating agreements and amounts from providing ancillary services to customers. The majority of other revenues are a reduction to gross revenue requirement when calculating net revenue requirement under our cost-based formula rates.

Operating Expenses

Operation and Maintenance Expenses consist primarily of the costs 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 and human resources organizations, general office expenses and fees for professional services. Professional services are principally composed of outside legal, audit and information technology services. Professional advisory and consulting services related to the terminated Entergy Transaction, as discussed in Note 17 to the consolidated financial statements, are also included in general and administrative expenses. We capitalize portions of certain general and administrative expenses such as compensation, office rent, utilities and information technology to property, plant and equipment.

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. We capitalize a portion of the depreciation expense for vehicles and equipment used in our construction activities to property, plant and equipment.

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 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)	2013			2012			(Decrease)			(Decrease)	2011			(Decrease)			(Decrease)
OPERATING REVENUES	$	941,272		$	830,535		$	110,737		13.3%	$	757,397		$	73,138		9.7%
OPERATING EXPENSES
Operation and maintenance	112,821			121,941			(9,120		)	(7.5)%	129,288			(7,347		)	(5.7)%
General and administrative	149,109			112,091			37,018			33.0%	82,790			29,301			35.4%
Depreciation and amortization	118,596			106,512			12,084			11.3%	94,981			11,531			12.1%
Taxes other than income taxes	65,824			59,701			6,123			10.3%	53,430			6,271			11.7%
Other operating (income) and expenses — net	(1,139		)	(769		)	(370		)	48.1%	(844		)	75			(8.9)%
Total operating expenses	445,211			399,476			45,735			11.4%	359,645			39,831			11.1%
OPERATING INCOME	496,061			431,059			65,002			15.1%	397,752			33,307			8.4%
OTHER EXPENSES (INCOME)
Interest expense	168,319			155,734			12,585			8.1%	146,936			8,798			6.0%
Allowance for equity funds used during construction	(30,159		)	(23,000		)	(7,159		)	31.1%	(16,699		)	(6,301		)	37.7%
Other income	(1,038		)	(2,401		)	1,363			(56.8)%	(2,881		)	480			(16.7)%
Other expense	6,571			4,218			2,353			55.8%	3,962			256			6.5%
Total other expenses (income)	143,693			134,551			9,142			6.8%	131,318			3,233			2.5%
INCOME BEFORE INCOME TAXES	352,368			296,508			55,860			18.8%	266,434			30,074			11.3%
INCOME TAX PROVISION	118,862			108,632			10,230			9.4%	94,749			13,883			14.7%
NET INCOME	$	233,506		$	187,876		$	45,630		24.3%	$	171,685		$	16,191		9.4%

Operating Revenues

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 the same period in 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.

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Operating revenues for the year ended December 31, 2013 include the network, regional cost sharing and scheduling, control and dispatch revenue accruals (deferrals) as calculated below:

														Total
											ITC Great			Net Revenue
Line	Item	ITCTransmission			METC			ITC Midwest			Plains			Deferrals
(In thousands)
1	Estimated net revenue requirement (network revenues recognized) (a)	$	241,641		$	204,504		$	274,269		$	5,747
2	Network revenues billed (b)	245,504			212,129			283,779			5,731
3	Network revenue accruals (deferrals) (line 1 — line 2)	(3,863		)	(7,625		)	(9,510		)	16
4	Regional cost sharing revenue deferrals (c)	(1,575		)	(4,364		)	(2,348		)	(86		)
5	Scheduling, control and dispatch revenue deferrals (d)	(1,102		)	(1,146		)	(1,179		)	—
6	Total net revenue deferral (line 3 + line 4)	$	(6,540	)	$	(13,135	)	$	(13,037	)	$	(70	)	$	(32,782	)

____________________________

(a) The calculation of net revenue requirement for our Regulated Operating Subsidiaries is described in “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cost-Based Formula Rates with True-Up Mechanism — Net Revenue Requirement Calculation.” The amount is estimated for each reporting period until such time as FERC Form No. 1’s are completed for our Regulated Operating Subsidiaries.

(b) Network revenues billed at our MISO Regulated Operating Subsidiaries are calculated based on the joint zone monthly network peak load multiplied by their effective monthly network rates for 2013 of $2.147 per kW/month, $2.5263 per kW/month and $7.805 per kW/month applicable to ITCTransmission, METC and ITC Midwest, respectively, adjusted for the actual number of days in the month less amounts recovered or refunded associated with our MISO Regulated Operating Subsidiaries 2011 true-up adjustments. The rates for 2013 include amounts for the collection and refund of the 2011 revenue accruals and deferrals and related accrued interest, but the revenues billed in 2013 associated with the 2011 revenue accruals and deferrals are not included in these amounts. On August 29, 2013, ITCTransmission’s projected network rate of $2.305 per kW/month and METC’s projected network rate of $2.781 per kW/month, in each case for the period from January 1, 2014 through December 31, 2014, were posted by MISO. ITC Midwest’s projected network rate of $8.795 per kW/month for the period from January 1, 2014 through December 31, 2014 was posted by MISO on November 26, 2013. Our rates at ITC Great Plains are billed ratably each month based on its annual projected net revenue requirement and include amounts for the collection and refund of the 2011 revenue accruals and deferrals and related accrued interest. ITC Great Plains' projected revenue requirement of $56.8 million for the period from January 1, 2014 through December 31, 2014 was posted by SPP on August 29, 2013.

(c) Regional cost sharing revenues are subject to a separate true-up mechanism whereby our Regulated Operating Subsidiaries accrue or defer revenues for any over- or under-recovery. The related revenue accruals or deferrals associated with regional cost sharing revenues are included in the regional cost sharing revenue amounts.

(d) Beginning in 2013, a significant portion of our MISO Regulated Operating Subsidiaries’ scheduling, control and dispatch revenues are subject to a separate true-up mechanism whereby our MISO Regulated Operating Subsidiaries accrue or defer revenues for any over- or under-recovery. The related revenue accruals and deferrals associated with the MISO Regulated Operating Subsidiaries’ scheduling, control and dispatch revenues are included in the scheduling, control and dispatch revenue amounts.

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Year ended December 31, 2012 compared to year ended December 31, 2011

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

											Percentage
	2012				2011				Increase		Increase
(In thousands)	Amount		Percentage		Amount		Percentage		(Decrease)		(Decrease)
Network revenues	$	669,048	80.6	%	$	637,807	84.2	%	$	31,241	4.9	%
Regional cost sharing revenues	122,626		14.8	%	87,304		11.5	%	35,322		40.5	%
Point-to-point	17,439		2.1	%	15,903		2.1	%	1,536		9.7	%
Scheduling, control and dispatch	15,077		1.8	%	11,583		1.5	%	3,494		30.2	%
Other	6,345		0.7	%	4,800		0.7	%	1,545		32.2	%
Total	$	830,535	100.0	%	$	757,397	100.0	%	$	73,138	9.7	%

Network revenues increased due primarily to higher net revenue requirements at our Regulated Operating Subsidiaries during the year ended December 31, 2012 as compared to the same period in 2011. Higher net revenue requirements were due primarily to higher rate base associated with higher balances of property, plant and equipment in-service and higher recoverable expenses due to higher operating expenses, partially offset by the final monthly recognition in January through May 2011 of the ITCTransmission rate freeze revenue deferral and the initial recognition of the FERC audit refund totaling $11.0 million during 2012 as discussed in Note 16 to the consolidated financial statements under “Commitments and Contingent Liabilities — FERC Audit of ITC Midwest.”

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

Point-to-point revenues increased due primarily to an increase in the number of point-to-point reservations.

Scheduling, control and dispatch revenues increased due primarily to a change in MISO's revenue distribution methodology for these types of revenues in 2012 compared to 2011. The new method was implemented by MISO in 2012 to better align the billing rates relating to these services with the projected expenses.

Operating revenues for the year ended December 31, 2012 include the network revenue accruals (deferrals) and regional cost sharing revenue accruals (deferrals) as calculated below:

														Total
											ITC Great			Net Revenue
Line	Item	ITCTransmission			METC			ITC Midwest			Plains			Deferrals
(In thousands)
1	Estimated net revenue requirement (network revenues recognized) (a)	$	239,952		$	199,648		$	236,938		$	3,482
2	Network revenues billed (b)	251,501			197,662			239,637			4,630
3	Network revenue accruals (deferrals) (line 1 — line 2)	(11,549		)	1,986			(2,699		)	(1,148		)
4	Regional cost sharing revenue accruals (deferrals) (c)	(1,393		)	(5,766		)	957			(5,254		)
5	Total net revenue deferrals   (line 3 + line 4)	$	(12,942	)	$	(3,780	)	$	(1,742	)	$	(6,402	)	$	(24,866	)

____________________________

(a) The calculation of net revenue requirement for our Regulated Operating Subsidiaries is described in “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cost-Based Formula Rates with True-Up Mechanism — Net Revenue Requirement Calculation.” The amount is estimated for each reporting period until such time as FERC Form No. 1’s are completed for our Regulated Operating Subsidiaries.

(b) Network revenues billed at our MISO Regulated Operating Subsidiaries are calculated based on the joint zone monthly network peak load multiplied by their effective monthly network rates for 2012 of $2.188 per kW/month, $2.409 per kW/month and $6.797 per kW/month applicable to ITCTransmission, METC and ITC Midwest, respectively, adjusted for the actual number of days in the month less amounts recovered or refunded associated with our MISO Regulated Operating Subsidiaries 2010 true-up adjustments. The rates for 2012 include amounts

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for the collection and refund of the 2010 revenue accruals and deferrals and related accrued interest and the revenues billed in 2012 associated with the 2010 revenue accruals and deferrals are not included in these amounts. Our rates at ITC Great Plains are billed ratably each month based on its annual projected net revenue requirement.

(c) Regional cost sharing revenues are subject to a separate true-up mechanism whereby our Regulated Operating Subsidiaries accrue or defer revenues for any over- or under-recovery. The related revenue accruals or deferrals associated with regional cost sharing revenues are included in the regional cost sharing revenue amounts.

Operating Expenses

Operation and maintenance expenses

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.

Year ended December 31, 2012 compared to year ended December 31, 2011

Operation and maintenance expenses decreased by $2.5 million due to increased cost efficiencies associated primarily with substation, breaker and relay maintenance activities, partially offset by higher vegetation management activities, $2.2 million due to a decrease in activities associated with surveying transmission overhead lines and $1.2 million due to lower operating and training expenses.

General and administrative expenses

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.

Year ended December 31, 2012 compared to year ended December 31, 2011

General and administrative expenses increased by $12.3 million due to higher legal, advisory and financial services fees for the Entergy Transaction, $8.7 million due to higher compensation-related expenses primarily for personnel additions and increases in bonuses earned in 2012 such as those described above under “Capital Project Updates and Other Recent Developments — Development Bonuses”, $2.6 million due to general business expenses primarily due to information technology support, $2.1 million due to the recognition of the Kansas V-Plan Project regulatory asset which reduced expenses in 2011 and did not occur in 2012, $2.1 million due to an increase in other professional services such as legal, advisory and financial services fees and $1.4 million due to increases in general facilities expenses.

Depreciation and amortization expenses

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 additions.

Year ended December 31, 2012 compared to year ended December 31, 2011

Depreciation and amortization expenses increased due primarily to a higher depreciable base resulting from property, plant and equipment additions.

Taxes other than income 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.

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Year ended December 31, 2012 compared to year ended December 31, 2011

Taxes other than income taxes increased due to higher property tax expenses primarily due to our MISO Regulated Operating Subsidiaries’ 2011 capital additions, which are included in the assessments for 2012 property taxes.

Other expenses (income)

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

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.

Allowance for Equity Funds Used During Construction (“AFUDC equity”) increased due primarily to higher balances of construction work in progress 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.

Year ended December 31, 2012 compared to year ended December 31, 2011

Interest expense increased due primarily to an increase in borrowing levels under our revolving and term loan credit agreements.

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

Income Tax Provision

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.

Year ended December 31, 2012 compared to year ended December 31, 2011

Our effective tax rates for the years ended December 31, 2012 and 2011 are 36.6% and 35.6%, respectively. Our effective tax rate in both years exceeded our 35% statutory federal income tax rate due primarily to state income taxes and expenses relating to the Entergy Transaction that were deemed non-deductible for tax purposes in 2012 and 2011, partially offset by the tax effects of AFUDC equity. We recorded a state income tax provision of $6.2 million (net of federal deductibility) during the year ended December 31, 2012, compared to a state income tax provision of $3.8 million (net of federal deductibility) for the year ended December 31, 2011. Included in the state income tax provision recorded during the year ended December 31, 2011 is the effect of the Michigan tax law change as discussed in Note 10 to the consolidated financial statements, which reduced the income tax provision by $4.6 million.

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 and term loan credit agreements (the terms of which are described in Note 8 to the consolidated financial statements). In addition, consistent with previous periods, 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. Also, as market conditions warrant, we may from time to time repurchase debt securities issued by us, in the open market, in privately negotiated transactions, by tender offer or otherwise. We expect that our capital requirements will arise principally from our need to:

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• 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, which are 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 the additional debt we expect to incur to fund our capital expenditures.

• Fund contributions to our retirement plans, as described in Note 11 to the consolidated financial statements. We expect to contribute up to $11.6 million to these plans in 2014. 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 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 4and16 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, however, 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 and term loan credit agreements and our cash and cash equivalents as needed to meet our short-term cash requirements. As of December 31, 2013, we had consolidated indebtedness under our revolving and term loan credit agreements of $511.2 million, with unused capacity under the agreements of $513.8 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, 2013 and 2012.

As of December 31, 2013, we have approximately $200.0 million of debt maturing within one year, which is likely to be refinanced with long-term debt. In addition, for our long-term capital requirements, 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.

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		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	Unsecured Credit Facility	A-	Baa1

____________________________

(a) On December 6, 2013, Standard and Poor’s Ratings Services upgraded the senior unsecured credit ratings of ITC Holdings and ITC Great Plains and reaffirmed the secured credit ratings of ITCTransmission, METC and ITC Midwest. All of the ratings have a stable outlook.

(b) On January 30, 2014, Moody’s Investor Service, Inc. reaffirmed the credit ratings for ITC Holdings and the operating subsidiaries. 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, 2013, we were in compliance with all debt covenants and 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)	2013			2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	233,506		$	187,876		171,685
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	118,596			106,512			94,981
Recognition of and refund and collection of revenue accruals and deferrals — including accrued interest	(11,972		)	(13,052		)	56,944
Deferred income tax expense	76,703			67,285			30,797
Tax benefit for excess tax deductions of share-based compensation	(4,302		)	(23,022		)	(28,114	)
Other	36,665			1,924			54,623
Net cash provided by operating activities	449,196			327,523			380,916
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(821,588		)	(802,763		)	(556,931	)
Other	(4,700		)	(6,298		)	(3,264	)
Net cash used in investing activities	(826,288		)	(809,061		)	(560,195	)
CASH FLOWS FROM FINANCING ACTIVITIES
Net issuance/repayment of long-term debt (including revolving and term loan credit agreements)	464,425			501,740			147,660
Issuance of common stock	10,042			14,189			18,993
Dividends on common stock	(84,129		)	(75,153		)	(70,363	)
Refundable deposits from and repayments to generators for transmission network upgrades — net	(5,955		)	(4,943		)	28,792
Tax benefit for excess tax deductions of share-based compensation	4,302			23,022			28,114
Other	(3,505		)	(9,474		)	(10,682	)
Net cash provided by financing activities	385,180			449,381			142,514
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	8,088			(32,157		)	(36,765	)
CASH AND CASH EQUIVALENTS — Beginning of period	26,187			58,344			95,109
CASH AND CASH EQUIVALENTS — End of period	$	34,275		$	26,187		58,344

Cash Flows From Operating Activities

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.

Year ended December 31, 2012 compared to year ended December 31, 2011

Net cash provided by operating activities decreased $53.4 million in 2012 compared to 2011. The decrease in cash provided by operating activities was due primarily to an increase in payments of operating expenses of $46.2 million, including legal, advisory, consulting and financial services fees for the Entergy Transaction, higher income taxes paid of $7.0 million and $6.5 million of additional interest payments (net of interest capitalized) during 2012 compared to 2011. These decreases were partially offset by an increase in cash received from operating revenues of $10.2 million.

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Cash Flows From Investing Activities

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.”

Year ended December 31, 2012 compared to year ended December 31, 2011

Net cash used in investing activities increased $248.9 million in 2012 compared to 2011. The increase in cash used in investing activities was due primarily to higher investments in property, plant and equipment during 2012 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, 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. See Note 8 to the consolidated financial statements for detail on the issuances and retirements of long-term debt.

Year ended December 31, 2012 compared to year ended December 31, 2011

Net cash provided by financing activities increased $306.9 million in 2012 compared to 2011. The increase in cash provided by financing activities was due primarily to the proceeds of $175.0 million received from the issuance of METC 3.98% Senior Secured Notes and ITC Midwest’s 3.50% First Mortgage Bonds, Series E and the net increase of $179.1 million in amounts outstanding under our revolving and term loan credit agreements. These increases were partially offset by higher net payments of $33.7 million associated with refundable deposits for transmission network upgrades.

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Contractual Obligations

The following table details our contractual obligations as of December 31, 2013:

			Less Than		1-3		4-5		More Than
(In thousands)	Total		1 Year		Years		Years		5 Years
Debt:
ITC Holdings Senior Notes	$	1,745,000	$	50,000	$	305,000	$	385,000	$	1,005,000
ITC Holdings term loan credit agreement	140,000		—		140,000		—		—
ITCTransmission First Mortgage Bonds	485,000		—		—		100,000		385,000
ITCTransmission revolving credit agreement	41,100		—		41,100		—		—
METC Senior Secured Notes	350,000		50,000		175,000		—		125,000
METC revolving credit agreement	67,200		—		67,200		—		—
ITC Midwest First Mortgage Bonds	525,000		—		40,000		—		485,000
ITC Midwest revolving credit agreement	111,000		—		111,000		—		—
ITC Great Plains revolving credit agreement	51,900		—		51,900		—		—
ITC Great Plains term loan credit agreement	100,000		100,000		—		—		—
Interest payments:
ITC Holdings Senior Notes	1,151,479		96,843		264,369		108,504		681,763
ITCTransmission First Mortgage Bonds	551,177		25,056		75,169		40,051		410,901
METC Senior Secured Notes	183,059		19,063		26,891		11,610		125,495
ITC Midwest First Mortgage Bonds	479,451		27,196		73,335		44,604		334,316
Operating leases	1,294		604		595		95		—
Purchase obligations	100,170		100,170		—		—		—
Regulatory liabilities — revenue deferrals, including accrued interest	69,567		33,120		36,447		—		—
Regulatory liabilities — FERC audit refund, including accrued interest	13,067		13,067		—		—		—
METC Easement Agreement	369,761		10,041		30,123		20,082		309,515
Total obligations	$	6,535,225	$	525,160	$	1,438,129	$	709,946	$	3,861,990

Interest payments included above relate only to our fixed-rate long-term debt outstanding at December 31, 2013. 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 2013, we paid $9.0 million of interest and commitment fees under our revolving and term loan credit agreements.

Purchase obligations represent commitments for materials, services and equipment that had not been received as of December 31, 2013, 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.

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 regulatory liabilities — FERC audit refund, including accrued interest, represents the refund and related interest as a result of the FERC audit of ITC Midwest as discussed in Note 16 to the consolidated financial statements.

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

47

December 31, 2050 and is subject to 10 automatic 50-year renewals thereafter unless METC gives notice of nonrenewal of at least one year in advance. Payments to Consumers Energy under the Easement Agreement are charged to operation and maintenance expense.

The contractual obligations table above excludes certain items, including certain long-term liabilities, due to uncertainty related 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. 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 of $188.4 million relating to the regulatory assets at December 31, 2013 that are described in Note 5 to the consolidated financial statements. We also may be required to record losses of $49.3 million relating to intangible assets at December 31, 2013 that are described in Note 6 to the consolidated financial statements. Additionally, we may be required to record gains of $153.2 million relating to regulatory liabilities at December 31, 2013, primarily for asset removal costs that have been accrued in advance of incurring these costs.

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 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.

48

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, 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. For goodwill impairment testing, we have the option to first assess qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If, after assessing the totality of events or circumstances, we determine it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, then performing the two-step impairment test per the FASB guidance is unnecessary. The qualitative factors evaluated include macroeconomic conditions, industry and market considerations, cost factors, overall financial performance, our historical share price as well as other industry specific considerations such as our regulatory environment and rate structure. However, if we conclude otherwise, then we are required to perform the first step of the two-step impairment test by calculating the fair value of the reporting unit and comparing the fair value with the carrying amount of the reporting unit. 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, 2013 and 2012, consolidated goodwill totaled $950.2 million. We completed our annual goodwill impairment test by performing a qualitative analysis for ITCTransmission, METC and ITC Midwest as of October 1, 2013 and determined that no impairment exists. There were no events subsequent to October 1, 2013 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 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. 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, the NERC, the Internal Revenue Service, or the Environmental Protection Agency.

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

49

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.

Pension and Postretirement Costs

We sponsor certain post-employment benefits for our employees, which include retirement plans and certain postretirement health care, dental and life insurance benefits. Our periodic costs and obligations associated with these post-employment plans are developed from actuarial valuations derived from a number of assumptions including rates of return on plan assets, the discount rate, 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 post-employment plans. For our 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, in determining the expected long-term return on plan assets. 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 $3,299.0 million at December 31, 2013. The total book value of our consolidated long-term debt and debt maturing within one year, excluding revolving and term loan credit agreements, was $3,100.9 million at December 31, 2013. 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, 2013. An increase in interest rates of 10% (from 7.0% to 7.7%, for example) at December 31, 2013 would decrease the fair value of debt by $125.2 million, and a decrease in interest rates of 10% at December 31, 2013 would increase the fair value of debt by $137.0 million at that date.

Revolving and Term Loan Credit Agreements

At December 31, 2013, we had a consolidated total of $511.2 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, 2013 would increase or decrease the total interest expense by $0.7 million, respectively, for an annual period on a constant borrowing level of $511.2 million.

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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. In June 2013, we settled and terminated $250.0 million and $225.0 million of 10-year and 30-year term interest rate swaps, respectively, in conjunction with the Senior Notes issued at ITC Holdings as described in Note 8 to the consolidated financial statements. As of December 31, 2013, we are not party to any derivative financial instruments.

Credit Risk

Our credit risk is primarily with DTE Electric, Consumers Energy and IP&L, which were responsible for 23.8%, 24.0% and 27.9%, respectively, or $221.0 million, $222.5 million and $259.4 million, respectively, of our consolidated billed revenues for 2013. These percentages of total billed revenues of DTE Electric, Consumers Energy and IP&L include the collection of 2011 revenue accruals and deferrals and exclude any amounts for the 2013 revenue accruals and deferrals that were included in our 2013 operating revenues, but will not be billed to our customers until 2015. 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. In general, if these customers do not maintain their investment grade credit rating or have a history of late payments, MISO and SPP may require them to provide MISO and the SPP with a letter of credit or cash deposit equal to the highest monthly invoiced amount over the previous twelve months.

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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	53
Report of Independent Registered Public Accounting Firm	54
Report of Independent Registered Public Accounting Firm	55
Consolidated Statements of Financial Position as of December 31, 2013 and 2012	56
Consolidated Statements of Operations for the Years Ended December 31, 2013, 2012 and 2011	57
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2013, 2012 and 2011	58
Consolidated Statements of Changes in Stockholders’ Equity for the Years Ended December 31, 2013, 2012 and 2011	59
Consolidated Statements of Cash Flows for the Years Ended December 31, 2013, 2012 and 2011	60
Notes to Consolidated Financial Statements	61
Schedule I — Condensed Financial Information of Registrant	102

52

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 (1992)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, 2013.

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, 2013. Deloitte & Touche LLP’s report, which expresses an unqualified opinion on the effectiveness of our internal control over financial reporting, is included herein.

53

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

ITC Holdings Corp.:

Novi, Michigan

We have audited the accompanying consolidated statements of financial position of ITC Holdings Corp. and subsidiaries (the “Company”) as of December 31, 2013 and 2012 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, 2013. 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, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, 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, 2013, based on the criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2014 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Detroit, Michigan

February 27, 2014

54

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, 2013, based on the criteria established in Internal Control - Integrated Framework (1992)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, 2013, based on the criteria established in Internal Control — Integrated Framework (1992)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, 2013 of the Company and our report dated February 27, 2014 expressed an unqualified opinion on those financial statements and financial statement schedule.

/s/ DELOITTE & TOUCHE LLP

Detroit, Michigan

February 27, 2014

55

ITC HOLDINGS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

	December 31,
(In thousands, except share data)	2013		2012
ASSETS
Current assets
Cash and cash equivalents	$	34,275	$	26,187
Accounts receivable	89,348		72,192
Inventory	31,986		37,357
Deferred income taxes	17,225		23,014
Regulatory assets — revenue accruals, including accrued interest	6,334		7,489
Prepaid and other current assets	12,370		31,987
Total current assets	191,538		198,226
Property, plant and equipment (net of accumulated depreciation and amortization of $1,330,094 and $1,269,810, respectively)	4,846,526		4,134,579
Other assets
Goodwill	950,163		950,163
Intangible assets (net of accumulated amortization of $21,616 and $18,397, respectively)	49,328		48,492
Other regulatory assets	179,068		180,378
Deferred financing fees (net of accumulated amortization of $15,261 and $17,838, respectively)	25,585		19,293
Other	40,035		33,678
Total other assets	1,244,179		1,232,004
TOTAL ASSETS	$	6,282,243	$	5,564,809
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	111,145	$	123,022
Accrued payroll	21,930		20,740
Accrued interest	53,049		44,708
Accrued taxes	29,805		28,117
Regulatory liabilities — revenue deferrals, including accrued interest	33,120		53,763
Refundable deposits from generators for transmission network upgrades	23,283		40,745
Debt maturing within one year	200,000		651,929
Other	27,047		40,287
Total current liabilities	499,379		1,003,311
Accrued pension and postretirement liabilities	53,704		53,243
Deferred income taxes	562,938		460,072
Regulatory liabilities — revenue deferrals, including accrued interest	36,447		28,613
Regulatory liabilities — accrued asset removal costs	67,571		75,477
Refundable deposits from generators for transmission network upgrades	19,328		7,623
Other	17,032		26,317
Long-term debt	3,412,112		2,495,298
Commitments and contingent liabilities (Notes 4 and 16)
STOCKHOLDERS’ EQUITY
Common stock, without par value, 100,000,000 shares authorized, 52,500,265 and 52,248,514 shares issued and outstanding at December 31, 2013 and 2012, respectively	1,014,435		989,334
Retained earnings	592,970		443,569
Accumulated other comprehensive income (loss)	6,327		(18,048		)
Total stockholders’ equity	1,613,732		1,414,855
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	6,282,243	$	5,564,809

See notes to consolidated financial statements.

56

ITC HOLDINGS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended December 31,
(In thousands, except per share data)	2013			2012			2011
OPERATING REVENUES	$	941,272		$	830,535		$	757,397
OPERATING EXPENSES
Operation and maintenance	112,821			121,941			129,288
General and administrative	149,109			112,091			82,790
Depreciation and amortization	118,596			106,512			94,981
Taxes other than income taxes	65,824			59,701			53,430
Other operating (income) and expense — net	(1,139		)	(769		)	(844		)
Total operating expenses	445,211			399,476			359,645
OPERATING INCOME	496,061			431,059			397,752
OTHER EXPENSES (INCOME)
Interest expense — net	168,319			155,734			146,936
Allowance for equity funds used during construction	(30,159		)	(23,000		)	(16,699		)
Other income	(1,038		)	(2,401		)	(2,881		)
Other expense	6,571			4,218			3,962
Total other expenses (income)	143,693			134,551			131,318
INCOME BEFORE INCOME TAXES	352,368			296,508			266,434
INCOME TAX PROVISION	118,862			108,632			94,749
NET INCOME	$	233,506		$	187,876		$	171,685
Basic earnings per common share	$	4.46		$	3.65		$	3.36
Diluted earnings per common share	$	4.42		$	3.60		$	3.31
Dividends declared per common share	$	1.605		$	1.460		$	1.375

See notes to consolidated financial statements.

57

ITC HOLDINGS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Year Ended December 31,
(In thousands)	2013		2012			2011
NET INCOME	$	233,506	$	187,876		$	171,685
OTHER COMPREHENSIVE INCOME (LOSS)
Derivative instruments, net of tax (Note 13)	24,304		(2,680		)	(16,556		)
Available-for-sale securities, net of tax (Note 13)	71		—			—
TOTAL OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX	24,375		(2,680		)	(16,556		)
TOTAL COMPREHENSIVE INCOME	$	257,881	$	185,196		$	155,129

See notes to consolidated financial statements.

58

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, 2010	50,715,805		$	886,808		$	229,437		$	1,188		$	1,117,433
Net income	—		—			171,685			—			171,685
Repurchase and retirement of common stock	(89,715	)	(6,401		)	—			—			(6,401		)
Dividends declared on common stock ($1.375 per share)	—		—			(70,363		)	—			(70,363		)
Stock option exercises	543,775		17,666			—			—			17,666
Shares issued under the Employee Stock Purchase Plan	23,027		1,327			—			—			1,327
Issuance of restricted stock	142,999		—			—			—			—
Forfeiture of restricted stock	(18,012	)	—			57			—			57
Vesting of deferred stock units	5,489		—			—			—			—
Share-based compensation, net of forfeitures	—		15,334			—			—			15,334
Tax benefit for excess tax deductions of share-based compensation	—		28,114			—			—			28,114
Other comprehensive loss, net of tax (Note 13)	—		—			—			(16,556		)	(16,556		)
Other	—		596			—			—			596
BALANCE, DECEMBER 31, 2011	51,323,368		$	943,444		$	330,816		$	(15,368	)	$	1,258,892
Net income	—		—			187,876			—			187,876
Repurchase and retirement of common stock	(99,533	)	(7,266		)	—			—			(7,266		)
Dividends declared on common stock ($1.460 per share)	—		—			(75,153		)	—			(75,153		)
Stock option exercises	851,720		12,593			—			—			12,593
Shares issued under the Employee Stock Purchase Plan	25,521		1,596			—			—			1,596
Issuance of restricted stock	158,599		—			—			—			—
Forfeiture of restricted stock	(11,161	)	—			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	52,248,514		$	989,334		$	443,569		$	(18,048	)	$	1,414,855
Net income	—		—			233,506			—			233,506
Repurchase and retirement of common stock	(54,440	)	(4,885		)	—			—			(4,885		)
Dividends declared on common stock ($1.605 per share)	—		—			(84,129		)	—			(84,129		)
Stock option exercises	166,338		8,165			—			—			8,165
Shares issued under the Employee Stock Purchase Plan	25,699		1,877			—			—			1,877
Issuance of restricted stock	128,192		—			—			—			—
Forfeiture of restricted stock	(14,038	)	—			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	52,500,265		$	1,014,435		$	592,970		$	6,327		$	1,613,732

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)	2013			2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	233,506		$	187,876		$	171,685
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	118,596			106,512			94,981
Recognition of and refund and collection of revenue accruals and deferrals — including accrued interest	(11,972		)	(13,052		)	56,944
Deferred income tax expense	76,703			67,285			30,797
Allowance for equity funds used during construction	(30,159		)	(23,000		)	(16,699		)
Other	17,864			13,772			13,361
Changes in assets and liabilities, exclusive of changes shown separately:
Accounts receivable	(16,312		)	1,721			2,434
Inventory	5,371			(2,502		)	7,431
Prepaid and other current assets	16,891			(25,102		)	1,134
Accounts payable	17,638			(5,400		)	12,573
Accrued payroll	1,619			1,583			(1,096		)
Accrued interest	8,341			1,066			917
Accrued taxes	6,113			24,247			34,279
Tax benefit on the excess tax deduction of common stock	(4,302		)	(23,022		)	(28,114		)
Other current liabilities	1,630			2,912			(246		)
Other non-current assets and liabilities, net	7,669			12,627			535
Net cash provided by operating activities	449,196			327,523			380,916
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(821,588		)	(802,763		)	(556,931		)
Proceeds from sale of marketable securities	20,844			5,935			3,839
Purchases of marketable securities	(22,250		)	(11,779		)	(8,136		)
Other	(3,294		)	(454		)	1,033
Net cash used in investing activities	(826,288		)	(809,061		)	(560,195		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	933,025			175,000			—
Borrowings under revolving credit agreements	1,090,100			1,355,150			1,065,215
Borrowings under term loan credit agreements	675,000			200,000			—
Retirement of long-term debt	(452,000		)	—			—
Repayments of revolving credit agreements	(1,146,700		)	(1,228,410		)	(917,555		)
Repayments of term loan credit agreements	(635,000		)	—			—
Issuance of common stock	10,042			14,189			18,993
Dividends on common stock	(84,129		)	(75,153		)	(70,363		)
Refundable deposits from generators for transmission network upgrades	32,281			33,310			35,768
Repayment of refundable deposits from generators for transmission network upgrades	(38,236		)	(38,253		)	(6,976		)
Tax benefit on the excess tax deduction of common stock	4,302			23,022			28,114
Other	(3,505		)	(9,474		)	(10,682		)
Net cash provided by financing activities	385,180			449,381			142,514
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	8,088			(32,157		)	(36,765		)
CASH AND CASH EQUIVALENTS — Beginning of period	26,187			58,344			95,109
CASH AND CASH EQUIVALENTS — End of period	$	34,275		$	26,187		$	58,344

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 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 Midwest Independent Transmission 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 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, 2013, 2012 and 2011:

	Year Ended December 31,
(In thousands)	2013		2012		2011
Supplementary cash flows information:
Interest paid (net of interest capitalized)	$	155,112	$	148,598	$	142,101
Income taxes paid — net	20,092		41,174		34,127
Supplementary non-cash investing and financing activities:
Additions to property, plant and equipment and other long-lived assets (a)	$	68,276	$	94,218	$	102,091
Allowance for equity funds used during construction	30,159		23,000		16,699

____________________________

(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, 2013, 2012 or 2011, 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, 2013 and 2012, 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 $109.4 million, $97.3 million and $85.8 million for 2013, 2012 and 2011, 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 2.2%, 2.4% and 2.4% for 2013, 2012 and 2011, 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 and removal costs incurred are deducted from regulatory liabilities. 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 $8.0 million, $7.0 million and $4.7 million for 2013, 2012 and 2011, 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.

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. 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 by performing a qualitative analysis for each of our MISO Regulated Operating Subsidiaries as of October 1, 2013 and determined that no impairment exists. There were no events subsequent to October 1, 2013 that indicated impairment of our goodwill. 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 and the amortization of our debt discounts for 2013, 2012 and 2011 of $4.1 million, $4.0 million and $3.8 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 obligation 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 2013. Our asset retirement obligations as of December 31, 2013 and 2012 of $5.7 million and $5.1 million, respectively, are included in other liabilities.

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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.

Generator Interconnection Projects — 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 have been 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 investment in transmission facilities are recorded to property, plant and equipment, and are recorded net of any contribution in aid of construction received from the generator pursuant to the provisions of the MISO or SPP tariff. 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.

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 our stock options, which have graded vesting schedules, on a straight-line basis over the requisite service period and not for each separately vesting portion of the award. 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.

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

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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 2009 and earlier. State and city jurisdictions that remain subject to examination range from tax years 2009 to 2012. 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

Presentation of Comprehensive Income

The guidance set forth by the FASB has been updated with respect to the presentation of comprehensive income in financial statements. Under this guidance, we are required to (1) disclose the changes in accumulated other comprehensive income (“AOCI”) by component and (2) disclose the effects on the line items of net income of significant amounts reclassified out of AOCI. We adopted this guidance as of January 1, 2013. For the year ended December 31, 2013, the requirements under (1) above are presented in the consolidated statements of comprehensive income and the requirements under (2) above are disclosed in Note 13 of this Form 10-K.

Balance Sheet Offsetting Requirements

The FASB has issued guidance to clarify the disclosure requirements regarding the nature of an entity’s rights of offset and related arrangements associated with its financial instruments and derivative instruments. The guidance requires entities to disclose, at a minimum, the following information in tabular format, separately for assets and liabilities: (a) the gross amounts of those recognized assets and those recognized liabilities; (b) the amounts offset to determine the net amounts presented in the statement of financial position; (c) the net amounts presented in the statement of financial position; (d) the amounts subject to an enforceable master netting arrangement or similar agreement; and (e) the net amount after deducting the amounts in (d) from the amounts in (c). We adopted this guidance as of January 1, 2013. As of December 31, 2013, we did not have any material assets or liabilities that were subject to the new disclosure requirements.

4. REGULATORY MATTERS

Start-up, Development and Pre-construction Regulatory Assets

As of December 31, 2013, we have recorded a total of $13.9 million of regulatory assets for start-up, development and pre-construction expenses, including associated 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.

Order on Formula Rate Protocols

On May 17, 2012, the FERC issued an order 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. On May 16, 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 to file revised formula rate protocols. On September 13, 2013, MISO and its member transmission owners, including our MISO Regulated Operating Subsidiaries, filed revised formula rate protocols which will 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. We do not expect the revised formula rate protocols to impact our results of operations, cash flows or financial condition.

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Complaint of IP&L

On September 14, 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.

On July 18, 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. On August 14, 2013, MISO made the required compliance filing to revise ITC Midwest’s Attachment FF of the MISO Tariff. On August 16, 2013, 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.

Rate of Return on Equity and Capital Structure Complaint

On November 12, 2013, 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 (the “joint complainants”) filed a 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 (“TO”), including ITCTransmission, METC and ITC Midwest (currently set at 12.38%) to be unjust and unreasonable. The joint complainants are seeking a FERC order reducing the base rates of return on equity used in our formula transmission rate to 9.15%. The complaint also alleges 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 (ITCTransmission, METC and ITC Midwest use their actual structures, targeting 60% equity). The complaint asks FERC to institute a uniform capital structure for MISO TOs in which the assumed equity component does not exceed 50%. The complaint also alleges the return on equity adders currently approved for ITCTransmission for being a member of a RTO and for ITCTransmission and METC for being an independent transmission owner are no longer just and reasonable, and seeks to have them terminated. In the event a refund is required upon resolution of the complaint, the joint complainants are seeking a refund effective date of November 12, 2013.

On January 6, 2014, ITCTransmission, METC and ITC Midwest filed responses with the FERC to the Section 206 complaint (jointly with other MISO TOs and separate supplemental responses), and plan to vigorously defend the use of the current return on equity, the current capital structures targeting 60% equity, and the approved equity adders for RTO membership and independence. The responses seek dismissal of the complaint, or a denial of it on merits, with prejudice, as the joint complainants failed to meet their burden under Section 206 of the FPA to show that the current base rate of return on equity, approved capital structure targeting 60% equity and return on equity adders approved for ITCTransmission and METC are no longer just and reasonable. Further, the responses argue that the current return on equity along with the adders and approved capital structures encourage transmission investment are especially appropriate given the benefits of the independent transmission company model and RTO membership, and provide testimony to demonstrate that the current return on equity, including the adders and the use of capital structures targeting 60% equity, remain just and reasonable. We believe the likelihood of an unfavorable outcome of the complaint as it relates to the request to eliminate our approved return on equity adders and modify our existing capital structures is remote. While we believe an unfavorable outcome of the complaint request to reduce the base rates of return on equity is reasonably possible, we do not believe the range of potential loss would have been material to the consolidated financial statements as of and for the year ended December 31, 2013. However, an unfavorable resolution of this aspect of the complaint could have a material impact on our future results of operations, cash flows and financial condition.

FERC Audit Refund

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

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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. The over- or under-collection typically results from differences between the projected revenue requirement used to establish the billing rate 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. 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.

The current and non-current regulatory assets are recorded in the consolidated statements of financial position in regulatory assets — revenue accruals, including accrued interest and other non-current assets, respectively. The current and non-current regulatory liabilities are recorded in regulatory liabilities — revenue deferrals, including accrued interest. 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, 2013:

(In thousands)	Total
Balance as of December 31, 2012	$	(72,168	)
Net refund of 2011 revenue deferrals and accruals, including accrued interest	47,061
Net revenue deferral for the year ended December 31, 2013	(32,782		)
Net accrued interest payable for the year ended December 31, 2013	(2,307		)
Balance as of December 31, 2013	$	(60,196	)

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

(In thousands)	Total
Current assets	$	6,334
Non-current assets — other	3,037
Current liabilities	(33,120		)
Non-current liabilities	(36,447		)
Balance as of December 31, 2013	$	(60,196	)

ITC Midwest’s Rate Discount

As part of the orders by the Iowa Utility Board (“IUB”) and the Minnesota Public Service 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

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recognized as a reduction in revenues when we provide the service and charge the reduced rate that includes the rate discount.

5. REGULATORY ASSETS AND LIABILITIES

Regulatory Assets

The following table summarizes the regulatory asset balances at December 31, 2013 and 2012:

(In thousands)	2013		2012
Regulatory Assets:
Revenue accruals:
Current (including accrued interest of $114 and $131 as of December 31, 2013 and 2012, respectively)	$	6,334	$	7,489
Non-current (including accrued interest of $27 and $17 as of December 31, 2013 and 2012, respectively)	3,037		2,719
Other:
ITCTransmission ADIT Deferral (net of accumulated amortization of $32,826 and $29,796 as of December 31, 2013 and 2012, respectively)	27,776		30,806
METC ADIT Deferral (net of accumulated amortization of $16,511 and $14,152 as of December 31, 2013 and 2012, respectively)	25,945		28,304
METC Regulatory Deferrals (net of accumulated amortization of $5,400 and $4,628 as of December 31, 2013 and 2012, respectively)	10,029		10,800
Income taxes recoverable related to AFUDC equity	75,798		57,135
ITC Great Plains start-up, development and pre-construction	13,916		14,117
Pensions and postretirement	15,079		28,847
Income taxes recoverable related to implementation of the Michigan Corporate Income Tax	8,869		8,869
Other	1,656		1,500
Total	$	188,439	$	190,586

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 2013, 2012 and 2011, 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 2013, 2012 and 2011, 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 2013, 2012 and 2011, 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 $8.2 million as of December 31, 2013, 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 theMichigan Corporate Income Tax

On May 25, 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. Recovery of the Michigan CIT regulatory asset requires FERC authorization upon ITC Holdings making an additional filing under Section 205 of the FPA to demonstrate that the costs to be recovered are just and reasonable. 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.

Regulatory Liabilities

The following table summarizes the regulatory liability balances at December 31, 2013 and 2012:

(In thousands)	2013		2012
Regulatory Liabilities:
Revenue deferrals (a):
Current (including accrued interest of $1,535 and $2,492 as of December 31, 2013 and 2012, respectively)	$	33,120	$	53,763
Non-current (including accrued interest of $581 and $473 as of December 31, 2013 and 2012, respectively)	36,447		28,613
Accrued asset removal costs	67,571		75,477
FERC audit refund (including accrued interest of $2,095 and $1,679 as of December 31, 2013 and 2012, respectively) (b)	13,067		12,651
Other (c)	2,968		—
Total	$	153,173	$	170,504

____________________________

(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.” As of December 31, 2013 and 2012, the FERC audit refund was recorded in the consolidated statements of financial position in other current liabilities and other liabilities, respectively.

(c) As of December 31, 2013, amount was recorded in other liabilities in the consolidated statements of financial position.

Accrued Asset Removal Costs

The carrying amount of the accrued asset removal costs represents the cumulative amount collected from customers to cover the estimated future costs to remove property, plant and equipment at retirement. 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. In addition, the regulatory liability is also adjusted for timing differences between when we recover legal asset retirement obligations in our rates and when we would recognize these costs 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 asset retirement obligations under the standards set forth by the FASB, within accumulated depreciation for rate-making purposes, which is a reduction to rate base.

6. GOODWILL AND INTANGIBLE ASSETS

Goodwill

At December 31, 2013 and 2012, 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.

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Intangible Assets

Pursuant to the METC acquisition in October 2006, we have identified intangible assets with finite lives derived from the portion of regulatory assets recorded on METC’s historical FERC financial statements that were not recorded on METC’s historical GAAP financial statements associated with the METC Regulatory Deferrals and the METC ADIT Deferral. The carrying amount of the intangible asset for METC Regulatory Deferrals at December 31, 2013 and 2012 is $25.7 million and $27.7 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, 2013 and 2012 is $11.5 million and $12.6 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 made 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 is $12.1 million and $8.2 million (net of accumulated amortization of $0.4 million and $0.3 million, respectively) as of December 31, 2013 and 2012, respectively. The amortization period for these intangible assets is 50 years.

During each of the years ended December 31, 2013, 2012 and 2011, we recognized $3.2 million, $3.1 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, 2013 to be as follows:

(In thousands)
2014	$	3,276
2015	3,276
2016	3,276
2017	3,276
2018	3,276
2019 and thereafter	32,948
Total	$	49,328

7. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment — net consisted of the following at December 31, 2013 and 2012:

(In thousands)	2013			2012
Property, plant and equipment
Regulated Operating Subsidiaries:
Property, plant and equipment in service	$	5,641,240		$	4,779,833
Construction work in progress	423,433			501,847
Capital equipment inventory	75,470			86,882
Other	22,460			22,481
ITC Holdings and other	14,017			13,346
Total	6,176,620			5,404,389
Less: Accumulated depreciation and amortization	(1,330,094		)	(1,269,810		)
Property, plant and equipment — net	$	4,846,526		$	4,134,579

Additions to property, plant and equipment in service and construction work in progress during 2013 and 2012 were due primarily for projects to upgrade or replace existing transmission plant to improve the reliability of our transmission systems in addition to generator interconnections and our ongoing development projects.

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8. DEBT

The following amounts were outstanding at December 31, 2013 and 2012:

(Amounts in thousands)	2013		2012
ITC Holdings 5.25% Senior Notes due July 15, 2013 (net of discount of $65) (a)	$	—	$	266,935
ITC Holdings 6.04% Senior Notes, Series A, due September 20, 2014 (a)	50,000		50,000
ITC Holdings 5.875% Senior Notes due September 30, 2016 (net of discount of $9 and $12, respectively)	254,991		254,988
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 $174 and $182, respectively)	254,826		254,818
ITC Holdings 6.05% Senior Notes due January 31, 2018 (net of discount of $644 and $802, respectively)	384,356		384,198
ITC Holdings 5.50% Senior Notes due January 15, 2020 (net of discount of $787 and $920, respectively)	199,213		199,080
ITC Holdings 4.05% Senior Notes due July 1, 2023 (net of discount of $677)	249,323		—
ITC Holdings 5.30% Senior Notes due July 1, 2043 (net of discount of $791)	299,209		—
ITC Holdings Term Loan Credit Agreement due August 23, 2013 (a)	—		200,000
ITC Holdings Term Loan Credit Agreement due September 30, 2016	140,000		—
ITC Holdings Revolving Credit Agreement due May 17, 2016	—		29,600
ITCTransmission 4.45% First Mortgage Bonds, Series A, due July 15, 2013 (net of discount of $6) (a)	—		184,994
ITCTransmission 6.125% First Mortgage Bonds, Series C, due March 31, 2036 (net of discount of $82 and $85, respectively)	99,918		99,915
ITCTransmission 5.75% First Mortgage Bonds, Series D, due April 1, 2018 (net of discount of $49 and $60, respectively)	99,951		99,940
ITCTransmission 4.625% First Mortgage Bonds, Series E, due August 15, 2043 (net of discount of $452)	284,548		—
ITCTransmission Revolving Credit Agreement due May 17, 2016	41,100		78,700
METC 5.75% Senior Secured Notes due December 10, 2015	175,000		175,000
METC 6.63% Senior Secured Notes due December 18, 2014 (a)	50,000		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 Revolving Credit Agreement due May 17, 2016	67,200		10,500
ITC Midwest 6.15% First Mortgage Bonds, Series A, due January 31, 2038 (net of discount of $423 and $441, respectively)	174,577		174,559
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		—
ITC Midwest Revolving Credit Agreement due May 31, 2017	111,000		115,300
ITC Great Plains Term Loan Credit Agreement due November 28, 2014 (a)	100,000		—
ITC Great Plains Revolving Credit Agreement due February 16, 2015	51,900		93,700
Total debt	$	3,612,112	$	3,147,227

____________________________

(a) As of December 31, 2013 and 2012, there was $200.0 million and $651.9 million, respectively, of debt included within debt maturing within one year that is classified as a current liability in the consolidated statements of financial position.

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The annual maturities of debt as of December 31, 2013 are as follows:

(In thousands)
2014	$	200,000
2015	226,900
2016	503,300
2017	201,000
2018	485,000
2019 and thereafter	2,000,000
Total	$	3,616,200

ITC Holdings

Term Loan Credit Agreements

On August 23, 2012, ITC Holdings entered into an unsecured, unguaranteed term loan credit agreement (the “2012 Term Loan”), under which ITC Holdings borrowed the maximum of $200.0 million available under the agreement. This borrowing was repaid in full as of December 31, 2013.

On February 15, 2013, ITC Holdings entered into an unsecured, unguaranteed term loan credit agreement (the “February 2013 Term Loan”), under which ITC Holdings originally borrowed the maximum of $250.0 million available under the agreement. The proceeds were used for general corporate purposes, including the repayment of borrowings under the ITC Holdings’ revolving credit agreement. This borrowing was repaid in full as of December 31, 2013.

On December 20, 2013, ITC Holdings entered into an unsecured, unguaranteed term loan credit agreement (the “December 2013 Term Loan”) with a borrowing capacity of $200.0 million, under which ITC Holdings borrowed $140.0 million. The proceeds were used for general corporate purposes, including the repayment of borrowings under the ITC Holdings’ revolving credit agreement. The December 2013 Term Loan is scheduled to mature on September 30, 2016. The weighted-average interest rate on the borrowing outstanding under this agreement was 1.3% at December 31, 2013.

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, the $200.0 million borrowed under the 2012 Term Loan, a portion of the amount borrowed under the February 2013 Term Loan and for general corporate purposes. The ITC Holdings Senior Notes are issued under its indenture. All issuances of ITC Holdings Senior Notes are unsecured.

ITCTransmission

Term Loan Credit Agreement

On July 11, 2013, ITCTransmission entered into an unsecured, unguaranteed term loan credit agreement due July 14, 2014, under which ITCTransmission borrowed the maximum of $185.0 million upon entering the agreement. The proceeds were used to repay its $185.0 million of 4.45% First Mortgage Bonds, Series A, due July 15, 2013. This borrowing was repaid in full as of December 31, 2013.

First Mortgage Bonds

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. 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

Senior Secured Notes

On October 26, 2012, METC issued $75.0 million aggregate principal amount of its 3.98% Senior Secured Notes, due October 26, 2042 (the “METC Senior Secured Notes”). The proceeds were used primarily to refinance existing indebtedness, fund capital expenditures and for general corporate purposes. The METC Senior Secured Notes are secured by a first mortgage lien on substantially all of its real property and tangible personal property.

Term Loan Credit Agreement

On January 31, 2014, METC entered into an unsecured, unguaranteed term loan credit agreement, 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. The term loan is scheduled to mature on February 2, 2015. Borrowings outstanding under the term loan will bear interest at variable rates comparable to our other term loan borrowings.

ITC Midwest

ITC Midwest closed on the $100.0 million of 3.50% First Mortgage Bonds, Series E, due January 2027 on January 19, 2012. The proceeds from the issuance were used to refinance existing indebtedness, partially fund capital expenditures and for general corporate purposes.

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

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. The weighted average interest rate on the borrowings outstanding under the term loan was 1.0% at December 31, 2013.

Derivative Instruments and Hedging Activities

We may use derivative financial instruments, including interest rate swap contracts, to manage our exposure to fluctuations in interest rates. The use of these financial instruments mitigates exposure to these risks and the variability of our operating results. We are not a party to leveraged derivatives and do not enter into derivative financial instruments for trading or speculative purposes. As of December 31, 2012, we held $175.0 million and $50.0 million of 10-year and 30-year interest rate swaps, respectively, with a weighted average fixed rate of 3.99% and 2.59%, respectively, associated with forecasted future issuance of fixed rate debt. In 2013, we settled and terminated $250.0 million and $225.0 million of 10-year and 30-year term interest rate swaps, respectively, 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	Gain (Loss) on Derivative			Settlement Date
(amounts in millions)
10-year interest rate swaps	$	250.0	3.39%	$	(15.0	)	June 2013
30-year interest rate swaps	225.0		2.84%	26.2			June 2013
Total	$	475.0		$	11.2

The interest rate swaps qualified for hedge accounting treatment and the net gain of $11.2 million was recorded net of tax in AOCI during 2013. This amount is being amortized as a component of interest expense over the lives of the related debt.

We did not have any outstanding derivative financial instruments as of December 31, 2013.

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Revolving Credit Agreements

At December 31, 2013, ITC Holdings and its Regulated Operating Subsidiaries had the following unsecured revolving credit facilities available, each of which bears interest at a variable rate based on the prime rate or LIBOR (subject to adjustment based on credit rating):

(Amounts in millions)	Total Available Capacity		Outstanding Balance (a)		Unused Capacity		Weighted Average Interest Rate on Outstanding Balance		Commitment Fee Rate (b)		Original Term	Date of Maturity
Revolving Credit Agreements:
ITC Holdings	$	200.0	$	—	$	200.0	n/a	(c)	0.20	%	5 years	May 2016
ITCTransmission	100.0		41.1		58.9		1.3%		0.125	%	5 years	May 2016
METC	100.0		67.2		32.8		1.3%		0.125	%	5 years	May 2016
ITC Midwest	175.0		111.0		64.0		1.2%		0.10	%	5 years	May 2017
ITC Great Plains	150.0		51.9		98.1		1.9%		0.25	%	4 years	February 2015
Total	$	725.0	$	271.2	$	453.8

____________________________

(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) Amounts outstanding would bear interest at a rate equal to LIBOR plus an applicable margin of 1.50% or at a base rate, which is defined as the higher of the prime rate, 0.50% above the federal funds rate or 1% above the one month LIBOR, plus an applicable margin of 0.50%, subject to adjustments based on ITC Holdings’ 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, 2013, we are in compliance with all debt covenants.

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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, 2013, 2012 and 2011 is presented in the following table:

	Year Ended December 31,
(In thousands, except per share and share data)	2013			2012			2011
Numerator:
Net income	$	233,506		$	187,876		$	171,685
Less: dividends declared — common and restricted shares	(84,104		)	(75,124		)	(70,305		)
Undistributed earnings	149,402			112,752			101,380
Percentage allocated to common shares (a)	99.1		%	98.7		%	98.3		%
Undistributed earnings — common shares	148,057			111,286			99,657
Add: dividends declared — common shares	83,351			74,202			69,200
Numerator for basic and diluted earnings per common share	$	231,408		$	185,488		$	168,857
Denominator:
Denominator for basic earnings per common share — weighted average common shares	51,912,128			50,820,838			50,289,905
Incremental shares for stock options and employee stock purchase plan — weighted average assumed conversion	429,540			742,557			788,918
Denominator for diluted earnings per common share — adjusted weighted average shares and assumed conversion	52,341,668			51,563,395			51,078,823
Per common share net income:
Basic	$	4.46		$	3.65		$	3.36
Diluted	$	4.42		$	3.60		$	3.31

____________________________

(a)	Weighted average common shares outstanding	51,912,128		50,820,838		50,289,905
	Weighted average restricted shares and deferred stock units
	(participating securities)	490,989		658,835		854,717
	Total	52,403,117		51,479,673		51,144,622
	Percentage allocated to common shares	99.1	%	98.7	%	98.3	%

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:

	2013	2012	2011
Outstanding stock options and ESPP shares (as of December 31)	1,723,276	1,603,429	2,100,056
Anti-dilutive stock options and ESPP shares (for the year ended December 31)	304,190	565,945	213,917

The preceding earnings per share and share data do not reflect the impact of the three-for-one stock split, which will be effective on February 28, 2014. See Note 20 for further information.

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10. INCOME TAXES

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

(In thousands)	2013			2012			2011
Income tax expense at 35% statutory rate	$	123,329		$	103,778		$	93,252
State income taxes (net of federal benefit)	9,110			6,247			4,766
AFUDC equity	(9,715		)	(7,207		)	(5,292		)
Entergy Transaction expenses (a)	(5,614		)	4,113			1,501
Other — net	1,752			1,701			522
Total income tax provision	$	118,862		$	108,632		$	94,749

____________________________

(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 on the Entergy Transaction.

Components of the income tax provision were as follows:

(In thousands)	2013		2012		2011
Current income tax expense	$	42,159	$	41,347	$	63,952
Deferred income tax expense	76,094		66,710		33,266
Benefits of operating loss carryforward	609		575		2,169
Change in Michigan tax law	—		—		(4,638		)
Total income tax provision	$	118,862	$	108,632	$	94,749

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)	2013			2012
Property, plant and equipment	$	(459,983	)	$	(378,196	)
METC regulatory deferral (a)	(13,743		)	(14,884		)
Acquisition adjustments — ADIT deferrals (a)	(14,945		)	(14,852		)
Goodwill	(117,493		)	(102,994		)
Net revenue accruals and deferrals, including accrued interest (a)	23,504			28,121
Pension and postretirement liabilities	11,864			9,706
State income tax NOLs (net of federal benefit)	16,573			11,759
Share-based compensation	12,040			10,281
Other — net	(3,530		)	14,001
Net deferred tax liabilities	$	(545,713	)	$	(437,058	)
Gross deferred income tax liabilities	$	(674,172	)	$	(572,088	)
Gross deferred income tax assets	128,459			135,030
Net deferred tax liabilities	$	(545,713	)	$	(437,058	)

____________________________

(a)Described in Note 5.

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We have state income tax net operating losses (“NOLs”) as of December 31, 2013, all of which we expect to use prior to their expiration. Our state income tax NOLs would expire beginning in 2027. We have recorded estimated state income tax NOL deferred tax assets of $16.6 millionand $11.8 million as of December 31, 2013 and 2012, respectively. We have additional state income tax NOLs of $6.1 million tax effected, net of federal benefit, 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.

Michigan Corporate Income Tax

On May25, 2011, the Michigan Business Tax was repealed and replaced with the Michigan Corporate Income Tax, effective January1, 2012. Under the CIT, we are taxed at a rate of 6.0% on federal taxable income apportioned to 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 remove deferred income tax balances recognized under the MBT and establish new deferred income tax balances under the CIT in the second quarter of 2011. The change in Michigan tax law resulted in a reduction of income tax provision of $4.6 million during 2011. Additionally, we recorded regulatory assets for this change in tax law as described in Note 5.

11. RETIREMENT BENEFITS AND ASSETS HELD IN TRUST

Retirement Plan Benefits

We have a qualified retirement plan for eligible employees, comprised of a traditional final average pay plan and a cash balance plan. The traditional final average pay plan is noncontributory, covers select employees, and provides retirement benefits based on the employees’ 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. While we are obligated to fund the retirement plan by contributing the minimum amount required by the Employee Retirement Income Security Act of 1974, as amended, it is our practice to contribute the maximum allowable amount as defined by section 404 of the Internal Revenue Code. We made contributions of $6.9 million, $7.0 million and $3.6 million to the retirement plan in 2013, 2012 and 2011, respectively, although we had no minimum funding requirements. We expect to contribute up to $8.6 million to the retirement plan relating to the 2013 plan year in 2014.

We have also established two supplemental nonqualified, noncontributory, retirement benefit plans (“supplemental benefit plans”) for selected management employees. The plans provide for benefits that supplement those provided by our other retirement plans. The obligations under these supplemental nonqualified plans are included in the pension benefit obligation calculations below. The investments in trust for the supplemental nonqualified retirement plans of $21.1 million and $22.4 million at December 31, 2013 and 2012, respectively, are not included in the pension plan asset amounts presented below, but are included in other assets on our consolidated statement of financial position. For the years ended December 31, 2013, 2012 and 2011, we contributed $0.6 million, $4.7 million and $3.1 million, respectively, to these supplemental nonqualified, noncontributory, retirement 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 and $2.2 million in 2012 and 2011, respectively, were 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, 2013, all of our investments held in the supplemental benefit plan were classified as available-for-sale securities and the unrealized gains of $0.1 million were recognized in the accumulated other comprehensive income component of equity.

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

Asset Category	2013		2012
Fixed income securities	47.7	%	48.4	%
Equity securities	52.3	%	51.6	%
Total	100.0	%	100.0	%

Net pension cost for 2013, 2012 and 2011 includes the following components:

(In thousands)	2013			2012			2011
Service cost	$	5,261		$	4,160		$	3,585
Interest cost	2,792			2,590			2,458
Expected return on plan assets	(2,868		)	(2,277		)	(1,896		)
Amortization of prior service credit	(42		)	(42		)	(42		)
Amortization of unrecognized loss	2,714			3,470			2,607
Net pension cost	$	7,857		$	7,901		$	6,712

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, 2013 and 2012:

(In thousands)	2013			2012
Change in Benefit Obligation:
Beginning projected benefit obligation	$	(72,400	)	$	(56,069	)
Service cost	(5,261		)	(4,160		)
Interest cost	(2,792		)	(2,590		)
Actuarial net gain (loss)	6,161			(10,481		)
Benefits paid	824			900
Ending projected benefit obligation	$	(73,468	)	$	(72,400	)
Change in Plans’ Assets:
Beginning plan assets at fair value	$	38,130		$	28,276
Actual return on plan assets	4,650			3,331
Employer contributions	6,938			7,023
Benefits paid	(824		)	(500		)
Ending plan assets at fair value	$	48,894		$	38,130
Funded status, underfunded	$	(24,574	)	$	(34,270	)
Accumulated benefit obligation	$	(61,832	)	$	(55,649	)
Amounts recorded as:
Funded Status:
Accrued pension liabilities	$	(35,003	)	$	(35,899	)
Pension assets — other assets — other	10,429			1,629
Total	$	(24,574	)	$	(34,270	)
Accumulated benefit obligation:
Qualified defined benefit retirement plan	$	(36,033	)	$	(33,051	)
Supplemental nonqualified retirement plans	(25,799		)	(22,598		)
Total	$	(61,832	)	$	(55,649	)
Unrecognized Amounts in Other Regulatory Assets:
Net actuarial loss	$	12,787		$	23,444
Prior service credit	(17		)	(59		)
Total	$	12,770		$	23,385

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The unrecognized amounts that otherwise would have been charged and/or credited to accumulated other comprehensive income associated with the guidance for employers’ accounting for pensions 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.

Actuarial assumptions used to determine the benefit obligation for 2013, 2012 and 2011 are listed below:

	2013	2012	2011
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%

Actuarial assumptions used to determine the benefit cost for 2013, 2012 and 2011 are listed below:

	2013	2012	2011
Discount rate	3.70 - 4.45%	4.50 - 5.00%	5.17 - 5.67%
Annual rate of salary increases	5.00 - 6.00%	5.00 - 6.00%	5.00 - 6.00%
Expected long-term rate of return on plan assets	7.00%	7.25%	7.25%

At December 31, 2013, the projected benefit payments for the defined benefit retirement plans calculated using the same assumptions as those used to calculate the benefit obligation described above are listed below:

(In thousands)
2014	$	1,507
2015	1,762
2016	1,661
2017	5,250
2018	5,657
2019 through 2023	33,361

Investment Objectives and Fair Value Measurement

The general investment objectives of the qualified retirement 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 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, 2013 and 2012, there were no transfers between levels.

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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 fair value measurement of the retirement plan assets as of December 31, 2012, 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:
Pooled separate accounts — U.S. equity securities	$	—	$	15,702	$	—
Pooled separate accounts — international equity securities	—		3,979		—
Pooled separate accounts — fixed income securities	—		15,824		—
Guaranteed deposit fund	—		2,625		—
Total	$	—	$	38,130	$	—

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 pooled separate accounts are valued at their estimated fair value by aggregating our proportionate share of the fair value of the underlying securities held by the accounts. The pooled separate accounts investments consist primarily of underlying publicly traded debt and equity securities for which market prices are readily available. 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 employees who may become eligible for these benefits. We contributed $1.5 million, $4.4 million and $3.4 million to the postretirement benefit plan in 2013, 2012 and 2011, respectively. We expect to contribute up to $3.0 million to the plan in 2014.

The plan assets consisted of the following assets by category:

Asset Category	2013		2012
Fixed income securities	46.6	%	49.8	%
Equity securities	53.4	%	50.2	%
Total	100.0	%	100.0	%

Our measurement of the accumulated postretirement benefit obligation as of December 31, 2013 and 2012 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 cost for 2013, 2012 and 2011 includes the following components:

(In thousands)	2013			2012			2011
Service cost	$	5,774		$	5,433		$	3,431
Interest cost	1,562			1,552			1,285
Expected return on plan assets	(1,415		)	(1,016		)	(737		)
Amortization of prior service cost	—			125			313
Amortization of unrecognized loss	220			534			220
Net postretirement cost	$	6,141		$	6,628		$	4,512

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, 2013 and 2012:

(In thousands)	2013			2012
Change in Benefit Obligation:
Beginning accumulated postretirement obligation	$	(37,015	)	$	(30,679	)
Service cost	(5,774		)	(5,433		)
Interest cost	(1,562		)	(1,552		)
Actuarial net gain	1,491			474
Benefits paid	154			175
Ending accumulated postretirement obligation	$	(42,706	)	$	(37,015	)
Change in Plan’s Assets:
Beginning plan assets at fair value	$	19,670		$	13,549
Actual return on plan assets	2,857			1,747
Employer contributions	1,477			4,374
Employer provided retiree premiums	154			175
Benefits paid	(154		)	(175		)
Ending plan assets at fair value	$	24,004		$	19,670
Funded status, underfunded	$	(18,702	)	$	(17,345	)
Amounts recorded as:
Funded Status:
Accrued postretirement liabilities	$	(18,702	)	$	(17,345	)
Total	$	(18,702	)	$	(17,345	)
Unrecognized Amounts in Other Regulatory Assets:
Net actuarial loss	$	2,309		$	5,461
Prior service credit	—			—
Total	$	2,309		$	5,461

The unrecognized amounts that otherwise would have been charged and or credited to accumulated other comprehensive income associated with the guidance for employers’ accounting for pensions are recorded as a regulatory asset on our consolidated statements of financial position. The amounts recorded as a regulatory asset represent a net periodic benefit cost to be recognized in our operating income in future periods.

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Actuarial assumptions used to determine the benefit obligation for 2013, 2012 and 2011 are as follows:

	2013	2012	2011
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
Annual rate of increase in dental benefit costs	5.00%	5.00%	5.00%

Actuarial assumptions used to determine the benefit cost for 2013, 2012 and 2011 are as follows:

	2013	2012	2011
Discount rate	4.20%	5.00%	5.49%
Annual rate of salary increases	5.00%	5.00%	5.00%
Health care cost trend rate assumed for next year	8.00%	9.00%	9.00%
Rate to which the cost trend rate is assumed to decline	5.00%	5.00%	5.00%
Expected long-term rate of return on plan assets	7.00%	7.25%	7.25%
Year that the rate reaches the ultimate trend rate	2017	2017	2017

At December 31, 2013, 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 listed below:

(In thousands)
2014	$	376
2015	482
2016	599
2017	766
2018	1,184
2019 through 2023	12,401

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 2013 and the postretirement benefit obligation at December 31, 2013:

	One-Percentage-		One-Percentage-
(In thousands)	Point Increase		Point Decrease
Effect on total of service and interest cost	$	1,400	$	(1,096	)
Effect on postretirement benefit obligation	7,449		(5,921		)

Investment Objectives and Fair Value Measurement

The general investment objectives of the qualified other postretirement benefit plans include maximizing the return within reasonable and prudent levels of risk and controlling administrative and management costs. The targeted asset allocation is weighted equally between equity and fixed income investments. Investment decisions are made by our retirement benefits board as delegated by our board of directors. Equity investments may include various types of U.S. and international equity securities, such as large-cap, mid-cap and small-cap stocks. Fixed income investments may include cash and short-term instruments, U.S. Government securities, corporate bonds, mortgages and other fixed income investments. No investments are prohibited for use in the other postretirement plan, including derivatives, but our exposure to derivatives currently is not material. We intend that the long-term capital growth of the other postretirement plans, 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 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, 2013 and 2012, there were no transfers between levels.

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	$	—

The fair value measurement of the other postretirement benefit plan assets as of December 31, 2012, 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	$	16	$	—	$	—
Pooled separate accounts — U.S. equity securities	—		2,131		—
Pooled separate accounts — international equity securities	—		529		—
Pooled separate accounts — fixed income securities	—		2,222		—
Mutual funds — equity securities	7,214		—		—
Mutual funds — fixed income securities	7,117		—		—
Guaranteed deposit fund	—		441		—
Total	$	14,347	$	5,323	$	—

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 pooled separate accounts are valued at their estimated fair value by aggregating our proportionate share of the fair value of the underlying securities held by the accounts. The pooled separate accounts investments consist primarily of underlying publicly traded debt and equity securities for which market prices are readily available. The guaranteed deposit fund is a group annuity contract and is valued at estimated fair value by discounting the

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related cash flows based on current yields of similar instruments with comparable durations that are quoted in active markets.

Defined Contribution Plan

We also sponsor a defined contribution retirement savings plan. Participation in this plan is available to substantially all employees. We match employee contributions up to certain predefined limits based upon eligible compensation and the employee’s contribution rate. The cost of this plan was $4.5 million, $3.8 million and $3.4 million in 2013, 2012 and 2011, respectively.

12. FAIR VALUE MEASUREMENTS

The measurement of fair value is based on a three-tier hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. Changes in economic conditions or model-based valuation techniques may require the transfer of financial instruments from one fair value level to another. In such instances, the transfer is reported at the beginning of the reporting period. For the years ended December 31, 2013 and 2012, there were no transfers between levels.

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	$	—	$	—

Our assets and liabilities measured at fair value subject to the three-tier hierarchy at December 31, 2012, 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	$	13,127	$	10,037		$	—
Mutual funds — fixed income securities	21,332		—			—
Mutual funds — equity securities	1,612		—			—
Interest rate swap derivatives	—		2,725			—
Financial liabilities measured on a recurring basis:
Interest rate swap derivatives	—		(31,507		)	—
Total	$	36,071	$	(18,745	)	$	—

As of December 31, 2013 and 2012, 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 Level 1 investments included in 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

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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 cash and cash equivalents that are classified as a Level 2 investment consist of deposits held with financial institutions that are then invested by the financial institution in money market mutual funds and common and collective trusts that are administered similar to money market funds. The underlying money market funds and common and collective trusts are recorded at cost plus accrued interest.

The assets and liabilities related to derivatives consisted of interest rate swaps discussed in Note 8. The fair value of our interest rate swap derivatives as of December 31, 2012 was determined based on a discounted cash flow method using LIBOR swap rates which are observable at commonly quoted intervals. In June 2013, we settled and terminated all outstanding derivatives.

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, 2013 and 2012.

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 $3,299.0 million and $3,072.9 million at December 31, 2013 and 2012, 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 $3,100.9 million and $2,619.4 million at December 31, 2013 and 2012, respectively.

Revolving and Term Loan Credit Agreements

At December 31, 2013 and 2012, we had a consolidated total of $511.2 million and $527.8 million, respectively, outstanding under our revolving and term loan credit agreements, which are variable rate loans. The fair value of these loans approximates book value based on the borrowing rates currently available for variable rate loans obtained from third party lending institutions. These fair values represent Level 2 under the three-tier hierarchy described above.

Other Financial Instruments

The carrying value of other financial instruments included in current assets and current liabilities, including cash and cash equivalents 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, 2013,ITC Holdings’ authorized capital stock consisted of:

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

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

As of December 31, 2013, there were 52,500,265 shares of our common stock outstanding (which includes restricted stock), no shares of preferred stock outstanding and 695 holders of record of our common stock.

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 further discussed in Note 20.

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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 ITC Holdings Revolving Credit Agreement, the ITCTransmission Revolving Credit Agreement, the METC Revolving Credit Agreement, the ITC Midwest Revolving Credit Agreement, each of the ITC Great Plains Revolving and Term Loan Credit Agreements and the note purchase agreements governing ITC Holdings’ 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. ITCTransmission, METC, ITC Midwest and ITC Great Plains are restricted by their revolving credit agreements in their ability to pay dividends to ITC Holdings. In the event of default on our revolving credit agreements or non-compliance with the covenants under our revolving credit agreements, we may not be able to disburse dividends from the regulated operating subsidiaries to ITC Holdings. ITCTransmission, METC, ITC Midwest and ITC Great Plains were in compliance with the covenants under their revolving credit agreements during 2013.

In addition to the restrictions imposed by the debt covenants described above, there are practical limitations on using the net assets of each of our Regulated Operating Subsidiaries as of December 31, 2013 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.

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Repurchases — In 2013, 2012 and 2011, we repurchased 54,440, 99,533 and 89,715 shares of common stock for an aggregate of $4.9 million, $7.3 million and $6.4 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.

Accumulated Other Comprehensive Income

The following table provides the components of changes in AOCI for the years ended December 31, 2013, 2012 and 2011:

	Year Ended December 31,
(in thousands)	2013			2012			2011
Balance at the beginning of period	$	(18,048	)	$	(15,368	)	$	1,188
Derivative instruments
Reclassification of net gain relating to interest rate cash flow hedges from AOCI to interest expense — net (net of tax of $436, $31 and $1 for the years ended December 31, 2013, 2012 and 2011, respectively)	(25		)	67			97
Gain (loss) on interest rate swaps relating to interest rate cash flow hedges (net of tax of $15,652, $1,777 and $10,705 for the years ended December 31, 2013, 2012 and 2011, respectively)	24,329			(2,747		)	(16,653		)
Derivative instruments, net of tax	24,304			(2,680		)	(16,556		)
Available-for-sale securities
Unrealized gain on available-for-sale securities (net of tax of $46 for the year ended December 31, 2013)	71			—			—
Available-for-sale securities, net of tax	71			—			—
Total other comprehensive income (loss), net of tax	24,375			(2,680		)	(16,556		)
Balance at the end of period	$	6,327		$	(18,048	)	$	(15,368	)

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 may 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. The SAFA terminates in July 2014. The shares of common stock may be offered in one or more selling periods. Any shares of common stock sold under the SAFA will be offered at market prices prevailing at the time of sale. Moreover, ITC Holdings will specify to the sales agent (i) the aggregate selling price of the shares of common stock to be sold during each selling period, and (ii) the minimum price below which sales may not be made. ITC Holdings will pay a commission equal to a mutually agreed upon rate with its agent, not to exceed 2% of the sales price of all shares of common stock sold through its agent under the SAFA, plus expenses. The shares we would issue under the SAFA will be registered under ITC Holdings’ shelf registration statement on Form S-3 (File No. 333-187994) filed on April 18, 2013 with the SEC. No shares have been issued under this agreement.

14. SHARE-BASED COMPENSATION

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 4,950,000 shares to employees, directors and consultants. The LTIP provides that no more than 3,250,000 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. The ESPP allows for the issuance of an aggregate of 180,000 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, 2013, 1,873,658 shares were available for future issuance under our LTIP and ESPP, including 1,723,276 shares issuable upon the exercise of outstanding stock options, of which 1,128,540 were vested.

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We recorded share-based compensation in 2013, 2012 and 2011 as follows:

(In thousands)	2013		2012		2011
Operation and maintenance expenses	$	1,617	$	1,933	$	2,540
General and administrative expenses	9,318		8,057		7,524
Amounts capitalized to property, plant and equipment	4,731		5,632		5,327
Total share-based compensation	$	15,666	$	15,622	$	15,391
Total tax benefit recognized in the consolidated statement of operations	$	4,557	$	3,807	$	3,976

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, 2013, 2012 and 2011, we recognized the tax effects of the excess tax deductions as an increase in common stock of $4.3 million, $23.0 million and $28.1 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 2013 was as follows:

			Weighted
	Number of		Average
	Options		Exercise Price
Outstanding at January 1, 2013 (1,030,594 exercisable with a weighted average exercise price of $38.10)	1,603,429		$	49.02
Granted	310,111		87.93
Exercised	(166,338	)	49.09
Forfeited	(23,926	)	79.03
Outstanding at December 31, 2013 (1,128,540 exercisable with a weighted average exercise price of $42.98)	1,723,276		$	55.60

Grant date fair value of the stock options awards granted during 2013, 2012 and 2011 was determined using a Black-Scholes option pricing model. The following assumptions were used in determining the weighted average fair value per option:

	2013			2012			2011
	Option Grants			Option Grants			Option Grants
Weighted average grant date fair value per option	$	21.17		$	16.58		$	18.77
Weighted average expected volatility (a)	29.3		%	29.8		%	29.8		%
Weighted average risk-free interest rate	1.1		%	1.0		%	2.1		%
Weighted average expected term (b)	6 years			6 years			6 years
Weighted average expected dividend yield	1.72		%	1.99		%	1.86		%
Estimated fair value of underlying shares	$	87.93		$	70.76		$	72.15

____________________________

(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, 2013, the aggregate intrinsic value and the weighted average remaining contractual term for all outstanding options were approximately $69.3 million and 5.8 years, respectively. At December 31, 2013, the aggregate intrinsic value and the weighted average remaining contractual term for exercisable options were $59.6 million and 4.3 years, respectively. The aggregate intrinsic value of options exercised during 2013, 2012 and 2011 were $53.2 million, $53.2 million and $20.5 million, respectively. At December 31, 2013, the total unrecognized compensation cost related to the unvested options awards was $6.9 million and the weighted average period over which it is expected to be recognized was 1.9 years.

We estimate that 1,698,016 of the options outstanding at December 31, 2013 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, 2013 was $55.24 per share, $68.9 million and 5.8 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, 2013 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 2013 was as follows:

	Number of		Weighted
	Restricted		Average
	Stock		Grant Date
	Awards		Fair Value
Unvested restricted stock awards at January 1, 2013	523,350		$	62.63
Granted	128,192		88.27
Vested	(175,182	)	52.99
Forfeited	(14,038	)	76.13
Unvested restricted stock awards at December 31, 2013	462,322		$	72.97

The weighted average grant date fair value of restricted stock awarded during 2012 and 2011 was $71.65 and $71.27 per share, respectively. The aggregate fair value of restricted stock awards as of December 31, 2013 was $44.3 million. The aggregate fair value of restricted stock awards that vested during 2013, 2012 and 2011 was $15.8 million, $25.1 million and $20.7 million, respectively. At December 31, 2013, the total unrecognized compensation cost related to the restricted stock awards was $17.8 million and the weighted average period over which that cost is expected to be recognized was 2.2 years.

As of December 31, 2013, we estimate that 419,237 shares of the restricted shares outstanding at December 31, 2013 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 $72.60 per share, $40.2 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 2013, 2012 and 2011, employees purchased 25,699, 25,521 and 23,027 shares, respectively, resulting in proceeds from the sale of our common stock of $1.9 million, $1.6 million and $1.3 million, respectively, under the ESPP. The total share-based compensation amortization for the ESPP was $0.4 million, $0.4 million and $0.3 million for the years ended December 31, 2013, 2012 and 2011, respectively.

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15. JOINTLY OWNED UTILITY PLANT/COORDINATED SERVICES

Our MISO Regulated Operating Subsidiaries have agreements with other utilities for the joint ownership of substation assets and transmission lines. We account for these jointly owned assets by recording property, plant and equipment for our percentage of ownership interest. Various agreements provide the authority for construction of capital improvements and 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 MISO 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, 2013:

	Net		Construction
(In thousands)	Investments (a)		Work in Progress
Substations	$	27,345	$	3,461
Lines	93,157		3,225
Total	$	120,502	$	6,686

____________________________

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

ITCTransmission

The Michigan Public Power Agency (the “MPPA”) has a 50.4% ownership interest in two ITCTransmission 345 kV transmission lines. ITCTransmission’s net investment in these two lines including jointly owned lines under construction totaled $25.1 million as of December 31, 2013. The MPPA’s ownership portion entitles them to approximately 234 MW of network transmission service over the ITCTransmission system. An Ownership and Operating Agreement with the MPPA provides ITCTransmission with authority for construction of capital improvements and for the operation and management of the transmission lines. The MPPA 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, 2013, METC had net investments in jointly owned assets within substations including jointly owned assets under construction totaling $13.3 million of which METC’s ownership percentages for these jointly owned substation assets ranged from 6.3% to 92.0%. In addition, the MPPA, the Wolverine Power Supply Cooperative, Inc. (the “WPSC”) and the Michigan South Central Power Agency, (the “MSCPA”), each have an ownership interest in several METC 345 kV transmission lines. This ownership entitles the MPPA, WPSC and MSCPA to approximately 608 MW of network transmission service over the METC transmission system. As of December 31, 2013, METC had net investments in jointly shared transmission lines totaling $41.1 million of which METC’s ownership percentages for these jointly owned lines ranged from 35.5% to 64.8%.

ITC Midwest

ITC Midwest has joint sharing of several substations and transmission lines with various parties. As of December 31, 2013, ITC Midwest had net investments in jointly shared substations facilities including jointly shared substations facilities under construction totaling $17.5 million of which ITC Midwest’s ownership percentages for these jointly owned substations facilities ranged from 28.0% to 80.0%. As of December 31, 2013, ITC Midwest had net investments in jointly shared transmission lines totaling $30.3 million of which ITC Midwest’s ownership percentage for these jointly owned lines ranged from 48.0% to 80.0%.

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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 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

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.

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Michigan Sales and Use Tax Audit

The Michigan Department of Treasury conducted a sales and use tax audit of ITCTransmission for the audit period April 1, 2005 through June 30, 2008 and has denied ITCTransmission’s use of the industrial processing exemption from use tax it has taken beginning January 1, 2007. ITCTransmission has certain administrative and judicial appeal rights.

ITCTransmission believes that its utilization of the industrial processing exemption is appropriate and intends to defend itself against the denial of such exemption. 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 the potential use tax liability associated with the exemptions taken by ITCTransmission through December 31, 2013 is estimated to be approximately $18.7 million, which includes approximately $3.8 million assessed for the audit period April 1, 2005 through June 30, 2008, including interest. ITCTransmission has not recorded this contingent liability as of December 31, 2013. However, in the event it becomes appropriate to record additional use tax liability relating to this matter, ITCTransmission 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. METC has also taken the industrial processing exemption, estimated to be approximately $11.3 million for periods still subject to audit; however, METC has not recorded any contingent liabilities as of December 31, 2013 associated with this matter. These higher use tax expenses would be included as components of net revenue requirements and resulting rates.

FERC Audit of ITC Midwest

Certain staff of the FERC (“FERC audit staff”) have conducted an audit of ITC Midwest’s compliance with certain of the FERC’s regulations and the conditions established in the 2007 FERC order approving the acquisition of the transmission assets of IP&L by ITC Midwest. In 2011, the FERC issued an order that identified certain findings and recommendations of FERC audit staff relating to specific aspects of the accounting treatment for the acquisition that requires adjustments to ITC Midwest’s annual revenue requirement calculations and corresponding refunds. In 2012, ITC Midwest filed a refund report with the FERC which included adjustments to ITC Midwest’s annual revenue requirement calculations and corresponding refunds. On January 30, 2013, the FERC accepted ITC Midwest’s refund report which included the amounts being refunded in 2014.

ITCTransmission and METC had applied an accounting treatment for their respective acquisitions similar to ITC Midwest, and on February 1, 2013, voluntarily filed compliance plans with FERC to address the findings raised with respect to the ITC Midwest audit. On July 5, 2013, the FERC accepted ITCTransmission’s and METC’s refund reports which included the amounts being refunded in 2014.

ITC Midwest, ITCTransmission and METC have recorded an aggregate regulatory liability for the refund and related interest of $13.1 million and $12.7 million as of December 31, 2013 and December 31, 2012, respectively, in the consolidated statements of financial position. The refund amounts were limited to 2010 and earlier periods. As a result of FERC’s acceptance of the refund reports, this matter is now closed.

Purchase Obligations and Leases

At December 31, 2013, we had purchase obligations of $100.2 million representing commitments for materials, services and equipment that had not been received as of December 31, 2013, 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 2014.

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 $0.8 million, $0.7 million and $0.7 million for the years ended December 31, 2013, 2012 and 2011, 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.”

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Future minimum lease payments under the leases at December 31, 2013 were:

(In thousands)
2014	$	604
2015	237
2016	178
2017	180
2018 and thereafter	95
Total minimum lease payments	$	1,294

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 the primary beneficiary of the variable interest under the agreement. Additionally, 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.

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”), 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 from year to year thereafter until terminated by either party upon not less than one year prior written notice to the other party.

Project Commitment. In the Minnesota regulatory proceeding to approve ITC Midwest’s December 2007 acquisition of the transmission assets of IP&L, ITC Midwest agreed to build a certain project in Iowa, the 345 kV

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Salem-Hazelton line, and made a commitment to use commercially reasonable best efforts to complete the project prior to December 31, 2011. In the event ITC Midwest is found to have failed to meet this commitment, the allowed 12.38% rate of return on the actual equity portion of its capital structure would be reduced to 10.39% until such time as ITC Midwest completes the project, and ITC Midwest would refund with interest any amounts collected since the close date of the transaction that exceeded what would have been collected if the 10.39% return on equity had been used. Certain regulatory approvals were needed from the IUB before construction of the project could commence, but due to the IUB’s case schedule, these approvals were not received until the second quarter of 2011. As a result of the delay in the receipt of the necessary regulatory approvals, the project was not completed by December 31, 2011. We have notified the Minnesota Public Utilities Commission that the Salem-Hazleton line was placed into service on April 25, 2013, and requested confirmation from the commission that ITC Midwest has satisfied its commitment and that no refund is due as a result of the project not being completed by December 31, 2011. We believe we used commercially reasonable best efforts to meet the December 31, 2011 deadline, and therefore, we believe the likelihood of any material effect on the financial statements from this matter is remote.

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 have entered into a maintenance agreement (the “Midwest Energy Agreement”) dated as of June 25, 2012, pursuant to which Midwest Energy has agreed to perform various field operations and maintenance service related to ITC Great Plains facilities associated with the KETA project. The Midwest Energy Agreement has 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. Services must continue to be provided for at least six months subsequent to the termination date in any case.

Concentration of Credit Risk

Our credit risk is primarily with DTE Electric, Consumers Energy and IP&L, which were responsible for approximately 23.8%, 24.0% and 27.9%, respectively, or $221.0 million, $222.5 million and $259.4 million, respectively, of our consolidated billed revenues for the year ended December 31, 2013. These percentages and amounts of total billed revenues of DTE Electric, Consumers Energy and IP&L include the collection of 2011 revenue accruals and deferrals and exclude any amounts for the 2013 revenue accruals and deferrals that were included in our 2013 operating revenues, but will not be billed to our customers until 2015. 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 of the difference between billed revenues and operating revenues. 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 the SPP have implemented strict credit policies for its members’ customers, which include customers using our transmission systems. In general, if these customers do not maintain their investment grade credit rating or have a history of late payments, MISO and the SPP may require them to provide MISO and the SPP with a letter of credit or cash deposit equal to the highest monthly invoiced amount over the previous twelve months.

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

95

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, 2013, 2012 and 2011, we expensed external legal, advisory and financial services fees related to the terminated Entergy Transaction of $43.1 million, $19.4 million and $7.0 million, respectively, and certain internal labor and associated costs related to the terminated Entergy Transaction of $7.8 million, $7.1 million and $1.6 million, respectively. Certain of the external costs were not deductible for income tax purposes for the years ended December 31, 2012 and 2011, but the costs incurred to date are deductible for the year ended December 31, 2013 upon the cancellation of the transaction. 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/
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 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

96

	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 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

	Regulated
	Operating		ITC Holdings			Reconciliations/
2011	Subsidiaries		and Other			Eliminations			Total
(In thousands)
Operating revenues	$	757,465	$	486		$	(554	)	$	757,397
Depreciation and amortization	94,520		461			—			94,981
Interest expense — net	58,795		88,609			(468		)	146,936
Income before income taxes	367,628		(101,194		)	—			266,434
Income tax provision (benefit)	143,416		(48,667		)	—			94,749
Net income	224,211		171,685			(224,211		)	171,685
Property, plant and equipment — net	3,404,091		11,732			—			3,415,823
Goodwill	950,163		—			—			950,163
Total assets (a)	4,711,274		2,845,182			(2,733,090		)	4,823,366
Capital expenditures	554,692		7,633			(5,394		)	556,931

____________________________

(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.

97

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
2013 (a)
Operating revenues	$	217,304	$	229,817	$	238,782	$	255,369	$	941,272
Operating income	112,881		110,994		130,822		141,364		496,061
Net income (b)	50,190		47,395		58,984		76,937		233,506
Basic earnings per share	$	0.96	$	0.90	$	1.12	$	1.47	$	4.46
Diluted earnings per share	$	0.95	$	0.90	$	1.12	$	1.45	$	4.42
2012 (a)
Operating revenues	$	196,713	$	197,375	$	214,801	$	221,646	$	830,535
Operating income	105,894		98,483		113,354		113,328		431,059
Net income	46,051		42,386		51,183		48,256		187,876
Basic earnings per share	$	0.90	$	0.82	$	0.99	$	0.93	$	3.65
Diluted earnings per share	$	0.88	$	0.81	$	0.98	$	0.92	$	3.60

____________________________

(a) During the years ended December 31, 2013 and 2012, we expensed external legal, advisory and financial services fees of $43.1 million and $19.4 million, respectively, and internal labor and related costs of approximately $7.8 million and $7.1 million, respectively, related to the Entergy Transaction. 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.

(b) 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 for the external costs related to the Entergy transaction incurred in 2013, 2012 and 2011 that originally were recorded as non-deductible for income tax provision purposes.

20. SUBSEQUENT EVENTS

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 will be distributed on February 28, 2014, to shareholders of record on February 18, 2014. The stock split will increase our outstanding common stock from approximately 52.5 million shares to approximately 157.5 million shares. Our historical outstanding shares and earnings per share will be recast upon the distribution.

The estimated pro forma impact of the stock split on our stockholders’ equity at December 31, 2013 is presented in the following table:

	Historical				Pro Forma
	December 31, 2013		Adjustment		December 31, 2013
(In thousands, except share data)	(Audited)		(Unaudited)		(Unaudited)
Common stock, without par value, 100,000,000 shares authorized, 52,500,265 shares issued and outstanding at December 31, 2013 (a)	$	1,014,435	$	—	$	1,014,435
Retained earnings	592,970		—		592,970
Accumulated other comprehensive income	6,327		—		6,327
Total stockholders’ equity	$	1,613,732	$	—	$	1,613,732

____________________________

(a) If the stock split had been paid at December 31, 2013, it would have increased the shares issued and outstanding on that date to 157,500,795. Authorized shares increased in January 2014 upon filing an amendment to the Articles of Incorporation with the State of Michigan.

98

The following table provides the estimated pro forma effects on our earnings per share, as calculated in Note 9, for the year ended December 31, 2013:

	Historical					Pro Forma
	December 31, 2013		Adjustment			December 31, 2013
(In thousands, except per share and share data)	(Audited)		(Unaudited)			(Unaudited)
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
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

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, 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B.     OTHER INFORMATION.

None.

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PART III

ITEM 10.     DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.

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

ITEM 11.     EXECUTIVE COMPENSATION.

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

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

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

Equity Compensation Plans

The Company makes equity-based grants to employees, directors and consultants under the 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, 2013 (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	1,723	$	55.60	1,874

____________________________

(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, 2013 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 3,250,000 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, 2013 and 2012
		Consolidated Statements of Operations for the Years Ended December 31, 2013, 2012 and 2011
		Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2013, 2012 and 2011
		Consolidated Statements of Changes in Stockholders’ Equity for the Years Ended December 31, 2013, 2012 and 2011
		Consolidated Statements of Cash Flows for the Years Ended December 31, 2013, 2012 and 2011
		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.

101

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)	2013		2012
ASSETS
Current assets
Cash and cash equivalents	$	26,853	$	22,546
Accounts receivable from subsidiaries	50,196		51,005
Prepaid assets	5,806		22,756
Other	1,496		4,775
Total current assets	84,351		101,082
Other assets
Investment in subsidiaries	3,450,989		3,052,902
Deferred income taxes	25,519		35,272
Deferred financing fees (net of accumulated amortization of $6,346 and $8,063, respectively)	11,241		7,308
Other	47,660		55,393
Total other assets	3,535,409		3,150,875
TOTAL ASSETS	$	3,619,760	$	3,251,957
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	6,300	$	8,594
Accrued payroll	21,930		20,740
Accrued interest	37,486		30,985
Derivative instruments	—		31,507
Debt maturing within one year	50,000		466,935
Other	3,583		1,484
Total current liabilities	119,299		560,245
Accrued pension and postretirement liabilities	53,704		53,243
Other	1,106		930
Long-term debt (net of discounts of $3,082 and $1,916, respectively)	1,831,918		1,222,684
STOCKHOLDERS’ EQUITY
Common stock, without par value, 100,000,000 shares authorized, 52,500,265 and 52,248,514 shares issued and outstanding at December 31, 2013 and 2012, respectively	1,014,435		989,334
Retained earnings	592,971		443,569
Accumulated other comprehensive income (loss)	6,327		(18,048		)
Total stockholders’ equity	1,613,733		1,414,855
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	3,619,760	$	3,251,957

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

102

SCHEDULE I — Condensed Financial Information of Registrant

ITC HOLDINGS CORP.

CONDENSED STATEMENTS OF OPERATIONS (PARENT COMPANY ONLY)

	Year Ended December 31,
(In thousands)	2013			2012			2011
Other income	$	1,487		$	2,165		$	2,556
General and administrative expense	(56,707		)	(31,833		)	(11,409		)
Interest expense	(98,660		)	(90,289		)	(88,618		)
Other expense	(3,609		)	(812		)	(517		)
LOSS BEFORE INCOME TAXES	(157,489		)	(120,769		)	(97,988		)
INCOME TAX BENEFIT	(72,798		)	(49,141		)	(47,545		)
LOSS AFTER TAXES	(84,691		)	(71,628		)	(50,443		)
EQUITY IN SUBSIDIARIES’ NET EARNINGS	318,197			259,504			222,128
NET INCOME	$	233,506		$	187,876		$	171,685

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

103

SCHEDULE I — Condensed Financial Information of Registrant

ITC HOLDINGS CORP.

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (PARENT COMPANY ONLY)

	Year Ended December 31,
(In thousands)	2013		2012			2011
NET INCOME	$	233,506	$	187,876		$	171,685
OTHER COMPREHENSIVE INCOME (LOSS)
Derivative instruments (net of tax of $16,087, $1,746 and $10,704 for the years ended December 31, 2013, 2012 and 2011, respectively)	24,304		(2,680		)	(16,556		)
Available-for-sale securities (net of tax of $46 for the year ended December 31, 2013)	71		—			—
TOTAL OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX	24,375		(2,680		)	(16,556		)
TOTAL COMPREHENSIVE INCOME	$	257,881	$	185,196		$	155,129

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

104

SCHEDULE I — Condensed Financial Information of Registrant

ITC HOLDINGS CORP.

CONDENSED STATEMENTS OF CASH FLOWS (PARENT COMPANY ONLY)

	Year Ended December 31,
(In thousands)	2013			2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	233,506		$	187,876		171,685
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in subsidiaries’ earnings	(318,197		)	(259,504		)	(222,128		)
Dividends from subsidiaries	169,973			127,412			304,244
Deferred income tax expense	(117,956		)	(87,861		)	(94,663		)
Intercompany tax payments from subsidiaries	112,008			83,144			86,226
Share-based compensation expense	15,667			15,622			15,392
Other	(226		)	2,438			3,423
Changes in assets and liabilities, exclusive of changes shown separately:
Accounts receivable from subsidiaries	(979		)	(9,677		)	(11,062		)
Prepaid and other current assets	16,948			(21,803		)	1,566
Accounts payable	(2,294		)	2,680			4,126
Accrued payroll	1,190			2,727			(593		)
Accrued interest	6,501			93			65
Tax benefit for excess tax deductions of share-based compensation	(4,302		)	(23,022		)	(28,114		)
Other current liabilities	2,099			20,954			26,144
Other non-current assets and liabilities, net	12,465			(65		)	1,008
Net cash provided by operating activities	126,403			41,014			257,319
CASH FLOWS FROM INVESTING ACTIVITIES
Equity contribution to subsidiaries	(339,770		)	(337,630		)	(472,964		)
Return of capital from subsidiaries	96,120			91,399			228,600
Proceeds from sale of marketable securities	20,844			5,935			3,839
Purchases of marketable securities	(22,250		)	(11,779		)	(8,136		)
Net cash used in investing activities	(245,056		)	(252,075		)	(248,661		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	548,484			—			—
Borrowings under revolving credit agreement	222,800			295,450			—
Borrowings under term loan credit agreements	390,000			200,000			—
Retirement of long-term debt	(267,000		)	—			—
Repayments of revolving credit agreement	(252,400		)	(265,850		)	—
Repayments of term loan credit agreements	(450,000		)	—			—
Issuance of common stock	10,042			14,189			18,993
Dividends on common stock	(84,129		)	(75,153		)	(70,363		)
Tax benefit for excess tax deductions of share-based compensation	4,302			23,022			28,114
Other	861			(7,291		)	(7,546		)
Net cash provided by (used in) financing activities	122,960			184,367			(30,802		)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	4,307			(26,694		)	(22,144		)
CASH AND CASH EQUIVALENTS — Beginning of period	22,546			49,240			71,384
CASH AND CASH EQUIVALENTS — End of period	$	26,853		$	22,546		$	49,240
Supplementary cash flows information:
Interest paid (net of interest capitalized)	$	90,224		$	88,303		$	86,649
Income taxes paid — net	20,092			41,174			34,127
Supplementary non-cash investing and financing activities:
Equity transfers to subsidiaries	6,213			6,470			12,892

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

105

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, 2013 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, 2013, the maturities of our debt outstanding were as follows:

(In thousands)
2014	$	50,000
2015	—
2016	395,000
2017	50,000
2018	385,000
2019 and thereafter	1,005,000
Total	$	1,885,000

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 $1,864.7 million and $1,707.2 million at December 31, 2013 and 2012, respectively. The total book value of the ITC Holdings Senior Notes, net of discount, was $1,741.9 million and $1,460.0 million at December 31, 2013 and 2012, respectively. At December 31, 2013, we had a total of $140.0 million outstanding under our term loan credit agreement, which is a variable rate loan. No amount was outstanding under our revolving credit agreement at December 31, 2013. At December 31, 2012, we had a total of $229.6 millionoutstanding under our revolving and term loan credit agreements. 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

Our debt instruments contain numerous financial and operating covenants that place significant restrictions on certain transactions, such as incurring additional indebtedness, engaging in sale and lease-back transactions, creating liens or other encumbrances, entering into mergers, consolidations, liquidations or dissolutions and paying

106

dividends. In addition, the covenants require us to meet certain financial ratios, such as maintaining certain debt to capitalization ratios. At December 31, 2013, we were in compliance with all debt covenants.

3.     RELATED-PARTY TRANSACTIONS

ITCTransmission, MTH, ITC Midwest and other subsidiaries paid cash dividends to ITC Holdings totaling $170.0 million, $127.4 million and $304.2 million in 2013, 2012 and 2011, respectively. ITCTransmission, MTH, ITC Midwest and other subsidiaries provided a return of capital to ITC Holdings totaling $96.1 million, $91.4 million and $228.6 million in 2013, 2012 and 2011, respectively.

Additionally, ITCTransmission paid $39.1 million, $18.9 million and $51.6 million to ITC Holdings under an intercompany tax sharing arrangement during 2013, 2012 and 2011, respectively. MTH paid $30.0 million, $17.6 million and $23.3 million to ITC Holdings under an intercompany tax sharing arrangement during 2013, 2012 and 2011, respectively. Additionally, ITC Midwest paid $33.6 million, $37.2 million and $11.3 million to ITC Holdings under an intercompany tax sharing arrangement during 2013, 2012 and 2011, respectively. ITC Great Plains paid $9.4 million and $4.3 million to ITC Holdings under an intercompany tax sharing arrangement during 2013 and 2012, respectively. No payments were made by ITC Great Plains in 2011.

107

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 27, 2014.

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 27, 2014
Joseph L. Welch	Executive Officer (principal executive officer)
/s/ CAMERON M. BREADY	Executive Vice President and Chief	February 27, 2014
Cameron M. Bready	Financial Officer (principal financial officer
	and principal accounting officer)
/s/ CHRISTOPHER H. FRANKLIN	Director	February 27, 2014
Christopher H. Franklin
/s/ EDWARD G. JEPSEN	Director	February 27, 2014
Edward G. Jepsen
/s/ WILLIAM J. MUSELER	Director	February 27, 2014
William J. Museler
/s/ HAZEL R. O’LEARY	Director	February 27, 2014
Hazel R. O’Leary
/s/ THOMAS G. STEPHENS	Director	February 27, 2014
Thomas G. Stephens
/s/ GORDON BENNETT STEWART, III	Director	February 27, 2014
Gordon Bennett Stewart, III
/s/ LEE C. STEWART	Director	February 27, 2014
Lee C. Stewart

108

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
3.2	Third Amended and Restated Bylaws of Registrant dated as of February 16, 2011 (filed with Registrant’s 2010 Form 10-K)
4.1	Form of Certificate of Common Stock (filed with Registrant’s Registration Statement on Form S-1, as amended, Reg. No. 333-123657)
4.3	Indenture, dated as of July 16, 2003, between the Registrant and BNY Midwest Trust Company, as trustee (filed with Registrant’s Registration Statement on Form S-1, as amended, Reg. No. 333-123657)
4.4	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)

109

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)

110

Exhibit No. Description of Exhibit

*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)
*10.35	Form of restricted stock award agreement for directors and 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 2005 Form 10-K)
*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)
*10.44	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 Form 8-K filed on August 18, 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)
*10.65	Form of Amended and Restated Special Bonus Plan of the Registrant, dated November 12, 2007 (filed with Registrant’s 2007 Form 10-K)
*10.68	Deferred Stock Unit Award Agreement, dated February 25, 2008, pursuant to the 2006 Long-Term Incentive Plan of Registrant, between the Registrant and Joseph L.Welch (filed with Registrant’s Form 10-Q for the quarter ended March 31, 2008)
*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)
*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)
*10.73	Form of Amendment to Restricted Stock Agreement under 2003 Plan (August 2008) (filed with Registrant’s Form 8-K filed on August 19, 2008)
*10.74	Form of Amendment to Management Stockholder’s Agreement (August 2008) (filed with Registrant’s Form 8-K filed on August 19, 2008)

111

Exhibit No. Description of Exhibit

*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)
10.89	Revolving Credit Agreement, dated as of February 11, 2011, among ITC Midwest LLC, as the Borrower, Various Financial Institutions and Other Persons from Time to Time Parties Hereto, as the Lenders, JPMorgan Chase Bank, N.A., as the Administrative Agent and J.P. Morgan Securities Inc., as Sole Lead Arranger and Sole Bookrunner (filed with Registrant’s Form 8-K filed on February 17, 2011)
10.90	Revolving Credit Agreement, dated as of February 16, 2011, among ITC Great Plains, LLC, as the Borrower, Various Financial Institutions and Other Persons from Time to Time Parties Hereto, as the Lenders, Credit Suisse AG, Cayman Islands Branch, as the Administrative Agent, Credit Suisse Securities (USA) LLC and Morgan Stanley Senior Funding, Inc., as Joint Lead Arrangers and Joint Bookrunners, and Morgan Stanley Senior Funding, Inc., as Syndication Agent (filed with Registrant’s Form 8-K filed on February 17, 2011)
10.94	Revolving Credit Agreement, dated as of May 17, 2011, among ITC Holdings Corp., as the borrower, various financial institutions and other persons from time to time parties hereto, as the lenders, JPMorgan Chase Bank, N.A., as administrative agent, J.P. Morgan Securities LLC and Barclays Capital, as joint lead arrangers and joint bookrunners, and Barclays Capital, as syndication agent (filed with Registrant’s Form 8-K on May 19, 2011)
10.95	Revolving Credit Agreement, dated as of May 17, 2011, among International Transmission Company, as the borrower, various financial institutions and other persons from time to time parties hereto, as the lenders, JPMorgan Chase Bank, N.A., as administrative agent, J.P. Morgan Securities LLC and Barclays Capital, as joint lead arrangers and joint bookrunners, and Barclays Capital, as syndication agent (filed with Registrant’s Form 8-K on May 19, 2011)
10.96	Revolving Credit Agreement, dated as of May 17, 2011, among Michigan Electric Transmission Company, LLC, as the borrower, various financial institutions and other persons from time to time parties hereto, as the lenders, JPMorgan Chase Bank, N.A., as administrative agent, J.P. Morgan Securities LLC and Barclays Capital, as joint lead arrangers and joint bookrunners, and Barclays Capital, as syndication agent (filed with Registrant’s Form 8-K on May 19, 2011)
*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)
10.99	Sales Agency Financing Agreement, dated July 27, 2011, between Registrant and Deutsche Bank Securities Inc. (filed with Registrant’s Form 8-K filed on July 27, 2011)
*10.102	Summary of annual corporate performance bonus plan as of February 2012 (filed with Registrant’s Form 10-Q for the quarter ended March 31, 2012)
10.103	ITC Midwest Revolving Credit Agreement dated as of May 31, 2012 (filed with Registrant's Form 8-K filed on June 1, 2012)
10.104	Form of Stock Option Agreement for Executive Officers under Second Amended and Restated 2006 LTIP (May 2012) (filed with Registrant’s Form 10-Q for the quarter ended June 30, 2012)
10.105	Form of Restricted Stock Award Agreement for Executive Officers under Second Amended and Restated 2006 LTIP (May 2012) (filed with Registrant’s Form 10-Q for the quarter ended June 30, 2012)

112

Exhibit No. Description of Exhibit

10.106	Term Loan Credit Agreement, dated August 23, 2012, among Registrant, various financial institutions and other persons from time to time parties hereto, as the Lenders, JPMorgan Chase Bank, N.A., as administrative agent for the Lenders, J.P. Morgan Securities LLC, Barclays Bank PLC, Deutsche Bank Securities, Inc. and Wells Fargo Securities, LLC, as joint lead arrangers and joint bookrunners, Barclays Bank PLC and Deutsche Bank Securities, Inc., as syndication agents and Wells Fargo Bank, National Association, as documentation agent (filed with Registrant's Form 8-K filed on August 27, 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)
10.114	Term Loan Credit Agreement, dated February 15, 2013, among Registrant, various financial institutions from time to time parties hereto, Wells Fargo Bank, National Association, as administrative agent for the Lenders, Bank of America, N.A., as documentation agent, Deutsche Bank Securities, Inc. and Morgan Stanley Senior Funding, Inc., as co-syndication agents and Wells Fargo Securities, LLC, Deutsche Bank Securities, Inc., Merrill Lynch, Pierce, Fenner & Smith Inc. and Morgan Stanley Senior Funding, Inc. as joint lead arrangers and joint bookrunners (filed with Registrant's Form 8-K on February 19, 2013)
10.116	First Amendment to ITC Great Plains Revolving Credit Agreement, dated as of April 9, 2013 (filed with Registrant's Form 8-K on April 12, 2013)
10.117	Amendment and Restatement of the April 1, 2001 Distribution-Transmission Interconnection Agreement by and between Michigan Electric Transmission Company, LLC as Transmission Provider and Consumers Energy Company as Local Distribution Company, effective March 1, 2013 (filed with Registrant’s Form 10-Q for the quarter ended March 31, 2013)
10.118	Term Loan Credit Agreement, dated May 30, 2013, among ITC Great Plains, LLC, various financial institutions, and JPMorgan Chase Bank, N.A., as administrative agent (filed with Registrant's Form 8-K on June 3, 2013)
10.119	Term Loan Credit Agreement, dated as of July 11, 2013, among International Transmission Company, various financial institutions, and Barclays Bank PLC, as administrative agent (filed with Registrant's Form 8-K on July 15, 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)
10.121	Amended and Restated Generator Interconnection Agreement entered into by and among Michigan Electric Transmission Company, LLC, Consumers Energy Company and the Midwest Independent Transmission System Operator, Inc., effective July 4, 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
12.1	Ratio of Earnings to Fixed Charges for ITC Holdings Corp.

113

Exhibit No. Description of Exhibit

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
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.

114

EX-10.115

EXHIBIT 10.115

FERC rendition of the electronically filed tariff records in Docket No. ER12-02651-000

Filing Data:

CID: C001344

Filing Title: SA 1756 METC-Consumers G479b

Company Filing Identifier: 603

Type of Filing Code: 10

Associated Filing Identifier: 324

Tariff Title: Midwest ISO Agreements

Tariff ID: 13

Payment Confirmation:

Suspension Motion: N

Tariff Record Data:

Record Content Description, Tariff Record Title, Record Version Number, Option Code:

SA 1756, METC-Consumers, 2.0.0, A

Record Narative Name:

Tariff Record ID: 5077

Tariff Record Collation Value: 1879139756 Tariff Record Parent Identifier: 4593

Proposed Date: 2012-12-01

Priority Order: 500

Record Change Type: CHANGE

Record Content Type: 1

Associated Filing Identifier: 326

Sixth Revised Service Agreement No. 1756

Public Version

AMENDED AND RESTATED

GENERATOR INTERCONNECTION AGREEMENT

entered into by the

Midwest Independent Transmission System Operator, Inc.

Michigan Electric Transmission Company

and

Consumers Energy Company

Amended and Restated

GENERATOR INTERCONNECTION AGREEMENT

by and among

Michigan Electric Transmission Company, LLC

and

Consumers Energy Company

and the

Midwest Independent Transmission System Operator, Inc.

Amended and Restated

GENERATOR INTERCONNECTION AGREEMENT

THIS Amended AND RESTATED GENERATOR INTERCONNECTION AGREEMENT(the “Agreement”) is made and entered into as of ---September 18, 2012 by and among Michigan Electric Transmission Company, LLC, a limited liability company with offices at 27175 Energy Way Novi, Michigan (herein referred to as “METC” or “Transmission Owner”), Consumers Energy

Company, a Michigan corporation with offices at One Energy Plaza, Jackson, Michigan (herein referred to as “Consumers” or “Interconnection Customer”), and the Midwest Independent Transmission System Operator, Inc., a non-profit, non-stock corporation organized and existing under the laws of the State of Delaware (herein referred to as “MISO” or “Transmission Provider”). Transmission Provider, Consumers and Transmission Owner each may be referred to individually as a “Party,” or collectively as the “Parties.” This Agreement amends, restates and replaces the August 1, 2011 Amendment and Restatement of the Generator Interconnection Agreement between the Transmission Owner, Transmission Provider and Consumers, effective on the Effective Date provided for below in Section 2.1.

WITNESSETH:

WHEREAS, Consumers owns and operates several electric generating assets (herein referred to as a Unit when discussing one of them, or as Generation Resources when referring to all of them) as described in Article 1. The Unit names and generating capability ratings of the Generation Resources are set forth in Exhibit A to this Agreement. Each Unit in the list is currently in commercial operation; and

WHEREAS, Transmission Provider has functional control of the operation of the Transmission System, as defined in Article 1 of this Agreement, and is responsible for providing transmission and interconnection service on the transmission facilities under its functional control; and

WHEREAS, Transmission Owner owns or operates the Transmission System, whose operations are subject to the functional control of the Transmission Provider, to which the Consumers’ Units are interconnected, as set forth in this Agreement; and

WHEREAS, it is necessary for Consumers’ Units to remain interconnected with the Transmission System (as defined in Article 1), in order for said Units to continue to operate; and

WHEREAS, the revised and restated Agreement is not intended to affect METC’s and Consumer’s obligations to each other with regard to the following agreements:

WHEREAS, Consumers and Transmission Owner have entered into an Operating Agreement, dated as of April 1, 2001, as amended and restated, (herein referred to as the “Operating Agreement”) that defines the operating responsibilities of the Transmission Owner with respect to the Transmission System and the obligations, rights and responsibilities of Consumers to provide ancillary services and to operate its Generation Resources in a manner that will not unduly interfere with the provision of Transmission Services by the Transmission Owner; and

WHEREAS, Consumers, Transmission Owner and Transmission Provider have entered into a Purchase and Sale Agreement for Ancillary Services, dated as of April 1, 2001, as amended and restated, that sets forth the terms and conditions under which Consumers shall use its Generation Resources to provide ancillary services to the Transmission Owner and Transmission Provider; and

WHEREAS, the Parties are willing to maintain the interconnection of Consumers’ Generation Resources with the Transmission System under the terms and conditions contained herein.

NOW, THEREFORE, in consideration of and subject to the mutual covenants contained herein, the Parties hereto agree as follows:

ARTICLE 1

DEFINITIONS

1.1 Whenever used in this Agreement, appendices, and attachments hereto, the following terms shall have the following meanings:

“Black Start Capability” shall mean a generating Unit that is capable of starting without an outside electrical supply. Said Units are specified in Exhibit A.

“Black Start Plan” shall mean a plan utilizing Black Start Capability designed and implemented by the Transmission Provider or Transmission Owner in conjunction with its interconnected generation and distribution customers, Distribution System Control, other electric systems, its Security Coordinator and ECAR, to energize portions of the Transmission System which are de-energized as a result of a widespread system disturbance.

“Black Start Service” shall mean the provision of service needed to energize a defined portion of the Transmission Owner’s Transmission System, including the start up of the Generation Resources and/or other generators, in accordance with the Transmission Provider’s or Transmission Owner’s Black Start Plan when local power from the Transmission System is unavailable or insufficient.

”Commission” shall mean the Federal Energy Regulatory Commission, or any successor agency.

“Connection Point” shall be the point where Consumers’ Interconnection Assets connect to Transmission Owner’s Interconnection Assets, as described in Exhibit B of this Agreement.

“Consumers’ Incremental Cost” shall mean Consumers’ actual hourly replacement cost of energy on Consumers’ Generation Resources, whether that energy is (a) produced by generation owned by or under contract to Consumers or (b) purchased from a third party.

“Consumers’ Interconnection Assets” shall mean the assets identified as belonging to Consumers in Exhibit B of this Agreement and all other assets that are necessary or desirable to interconnect a Unit to the Transmission System reliably and safely, including all connection, switching, transmission, distribution, safety, and communication assets, protective assets, Telemetry and Monitoring Assets that Consumers owns or operates and maintains.

“Consumers’ System” shall mean the assets owned, controlled and operated by Consumers that are used to provide service to its customers.

“ECAR” stands for the East Central Area Reliability council or a successor group.

”Emergency” shall mean any system condition that requires automatic or immediate manual action to prevent or limit the loss of transmission assets or generation supply that could adversely affect the reliability of Transmission System or Consumers’ System or the systems to which either Party is directly or indirectly connected.

“Generation Resources” shall mean the assets used for the production of electric energy, which are owned and operated by Consumers and directly or indirectly connected to the

Transmission System pursuant to this Agreement.

”Good Utility Practice” shall mean any of the practices, methods and acts engaged in or approved by a significant proportion of the electric utility industry during the relevant time period, or any of the practices, methods and acts which, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety and expedition. Good Utility Practice is not intended to be limited to the optimum practice, method or act to the exclusion of all others, but rather to be acceptable practices, methods or acts generally accepted in the region.

“Governmental Authority” shall mean any federal, state, local or municipal governmental body; any governmental, regulatory or administrative agency, commission, body or other authority exercising or entitled to exercise any administrative, executive, judicial, legislative, policy, regulatory or taxing authority or power; or any court or governmental tribunal.

”Hazardous Substances” shall mean any chemicals, materials or substances defined as or included in the definition of “hazardous substances”, “hazardous wastes”, “hazardous materials”, “hazardous constituents”, “restricted hazardous materials”, “extremely hazardous substances”, “toxic substances”, “contaminants”, “pollutants”, “toxic pollutants” or words of similar meaning and regulatory effect under any applicable Environmental Law, or any other chemical, material or substance, exposure to which is prohibited, limited or regulated by any applicable Environmental Law. For purposes of this Agreement, the term “Environmental Law” shall mean federal, state, and local laws, regulations, rules, ordinances, codes, decrees, judgments, directives, or judicial or administrative orders relating to pollution or protection of the environment, natural resources or human health and safety.

“IEEE” is an acronym, which stands for the Institute of Electrical and Electronic Engineers.

“Interconnection Assets” shall mean, collectively, Transmission Owner’s Interconnection Assets and Consumers’ Interconnection Assets, or the specific Interconnection Assets of either the Transmission Owner or Consumers, as the case may be.

“Jointly Owned Assets” shall mean those assets in which Consumers and Transmission Owner have undivided ownership interests. Due to the nature of substation designs, many of the supporting substation assets (e.g., station batteries, fencing, control houses, ground grid, yard stone, steel structures and some protective relay assets) cannot be separated by ownership and the Parties share in the ownership of such assets. The respective ownership of such assets by substation is shown in Exhibit B hereto.

“Metering Assets” shall mean the assets required to provide acceptably accurate metering of the interconnection power and energy output from the Unit and the standby power and energy usage of the Unit. Said Metering Assets typically includes but is not limited to, metering accuracy potential and current transformers, transducers, primary connections, secondary connections, secondary potential and current circuits and conduit, telephone lines and access to said Metering Assets, if necessary. The transducers used shall be capable of providing Megawatthour and Megavarhour data.

“MISO” shall mean the Midwest Independent Transmission System Operator, Inc., or its successor.

“MISO Tariff” shall mean the Open Access Transmission, Energy and Operating Reserve Markets Tariff on file with the Commission as it may be amended or superseded from time to time.

“Monitoring Assets” shall mean the assets required to determine (a) the sequence of events for the operation of protective assets during an electrical fault, (b) the location and characteristics of an electrical fault and (c) the quality of power provided at the Point of Receipt.

”NERC” is an acronym that stands for the North American Electric Reliability Council, including any successor thereto or any regional reliability council thereof. This reliability council oversees the development and publication of operating policies, engineering planning principles and guides and support information to provide guidance to the regional reliability councils and to promote electric system reliability.

“Point of Receipt” shall be the point at which capacity and energy is provided by Consumers, as described in Exhibit B of this Agreement.

“Reactive Design Limitations” shall mean the reactive power capability designed into the Unit, which were consistent with reactive power capability specifications in place when the Unit was constructed.

”Secondary Systems” shall mean control or power circuits that operate below 600 volts, AC or DC, including, but not limited to, any hardware, control or protective devices, cables, conductors, electric conduits and raceways, secondary assets panels, transducers, batteries, chargers, and voltage and current transformers.

”Switching and Tagging Rules” shall mean the written documents describing the switching and tagging procedures of Transmission Owner and Consumers, as they may be amended.

“System Operator” is a generic term used to describe the individuals responsible for the integrity or the operational control of the Transmission System and any successor thereto.

”System Protection Assets” shall mean the assets required to protect (a) the Transmission System, the systems of others connected to the Transmission System, and Transmission Owner’s customers from faults occurring at the Unit, and (b) the Unit from faults occurring on the Transmission System or on the systems of others to which the Transmission System is directly or indirectly connected.

“Telemetry Equipment” shall mean the assets, identified by Transmission Owner, that are required to provide the necessary, real-time telemetry of Unit operations and status, as required by Transmission Owner, for remote monitoring and control purposes. This typically includes but is not limited to, remote terminal units, distributed terminal units, telemetry signal inputs, fiber optic communication connections, transducers, pulse multipliers, isolation amplifiers, analog inputs, digital inputs, metering pulsed accumulator inputs, power supply, dedicated telephone data line to remote terminal units, telephone modem, telephone switching, interface terminal strips for landing signal inputs/outputs. Telemetry Equipment may be located at Consumers’ Unit and or at Transmission Owner’s assets.

“Transmission Owner” shall mean Michigan Electric Transmission Company, LLC or its successor.

“Transmission Owner’s Interconnection Assets” shall mean the assets identified as belonging to Transmission Owner in Exhibit B of this Agreement and all other assets that are necessary or desirable to interconnect the Generation Resources to the Transmission System reliably and safely, including all connection, switching, transmission, distribution, safety, and communication assets, protective assets, Metering, Telemetry and Monitoring Assets and all improvements, additions or extensions to the Transmission System owned or operated and maintained by the Transmission Owner and that are attributable to or necessitated by the Generation Resources.

“Transmission Provider” shall mean MISO.

”Transmission System” shall mean the facilities owned by the Transmission Owner and controlled or operated by the Transmission Provider or Transmission Owner that are used to provide transmission service under the MISO Tariff.

“Transmission Service” shall include both Point-To-Point Transmission Service and Network Integration Transmission Service provided under the MISO Tariff.

”Unit” shall mean each of Consumers’ electric generating assets, or group of generating assets having common Interconnection Assets, covered by this Agreement and identified generally in the first “Whereas” clause and Exhibit A of this Agreement and more specifically identified in the “as built” drawings provided to Transmission Owner in accordance with Section 4.3 of this Agreement, together with the other property, assets, and assets owned and/or controlled by Consumers on the Consumers’ side of the Connection Point.

ARTICLE 2

TERM OF AGREEMENT

2.1Effective Date

This Agreement shall become effective on the date designated by the Commission in its order accepting this Agreement for filing (the “Effective Date”).

2.2Term

This Agreement shall become effective as provided in Section 2.1 above and, unless terminated as provided below, shall continue in full force and effect until a mutually agreed termination date, but no later than the date on which all of the Generation Resources cease commercial operation.

2.3Termination

In the event that Transmission Owner joins a Regional Transmission Organization (“RTO”) which requires use of its own FERC-approved interconnection and operating agreement, this Agreement shall terminate on the effective date of such new interconnection and operating agreement between Consumers and the RTO, except to the extent necessary to resolve billing and other outstanding matters related to service rendered under this Agreement as specified in Section 2.5.

2.4Regulatory Filing

Transmission Provider shall file this Agreement with the Commission as a Service Agreement under the MISO Tariff, within the meaning of 18 C.F.R. Part 35. Consumers and Transmission Owner agree to cooperate with Transmission Provider with respect to such filing and to provide any information, including the rendering of testimony reasonably requested by Transmission Provider, needed to comply with applicable regulatory requirements.

2.5Survival

The applicable provisions of this Agreement shall continue in effect after expiration, cancellation, or termination hereof to the extent necessary to provide for final billings, billing adjustments, and the determination and enforcement of liability and indemnification obligations arising from acts or events that occurred while this Agreement was in effect.

ARTICLE 3

INTERCONNECTION SERVICE

3.1Scope of Service

In the event future changes in either (a) design or operation of any Unit, (b) Consumers’ requirements or (c) Transmission Provider’s or Transmission Owner’s requirements resulting from the Unit’s parallel operation with the Transmission System later necessitate additional Interconnection Assets or modifications to the then existing Interconnection Assets herein, the Parties shall undertake such additions and modifications as may be necessary. Before undertaking such future additions or modifications, the Parties shall consult, develop plans and coordinate schedules of activities, including the making of necessary amendments to this Agreement (including its Appendices) and/or entering into new agreements, so as to insure continuous and reliable operation of the Interconnection Assets. The cost of such additions or modifications to the Interconnection Assets shall be borne by Consumers unless otherwise agreed upon at the time. The ownership, operation and maintenance responsibilities for any such future additions or modifications shall be made consistent with the responsibilities allocated in this Agreement.

3.1.1Except as otherwise provided under Sections 5.8 and 5.9 of this Agreement, neither Transmission Provider nor Transmission Owner shall have an obligation under this Agreement to pay Consumers any wheeling or other charges for electric power and/or energy transferred through Consumers’ assets or for power or ancillary services provided by Consumers under this Agreement for the benefit of the Transmission System.

3.1.2Except as otherwise provided under this Agreement, neither Transmission Provider nor Transmission Owner shall have an obligation under this Agreement to make arrangements or pay under applicable tariffs for transmission and ancillary services associated with the delivery of electricity and ancillary electrical products produced by the Unit.

3.1.3Except as otherwise provided under this Agreement, neither Transmission Provider nor Transmission Owner shall have an obligation under this Agreement to procure electricity and ancillary electrical products to satisfy Consumers’ station power needs or other related requirements.

3.1.4Except as otherwise provided under this Agreement, neither Transmission Provider nor Transmission Owner shall have an obligation under this Agreement to make arrangements under applicable tariffs for transmission, losses, and ancillary services associated with the use of the Transmission System for the delivery of electricity and ancillary electrical products to the Unit.

3.1.5Transmission Provider makes no representations to Consumers regarding the availability of Transmission Service on the Transmission System, and Consumers agrees that the availability of Transmission Service on the Transmission System may not be inferred or implied from Transmission Provider’s or Transmission Owner’s execution of this Agreement. Consumers will obtain Transmission Service on the Transmission System under a separate agreement between the Parties and in accordance with the provisions of the MISO Tariff.

3.2Third-Party Actions

Consumers acknowledges and agrees that, from time to time during the term of this Agreement, other persons may develop, construct and operate, or acquire and operate generating assets in the Transmission Provider’s service territory, and construction or acquisition and operation of any such assets, and reservations by any such persons of Transmission Service under the MISO Tariff may adversely affect the Unit and the availability of Transmission Service for the Unit’s electric output. Consumers acknowledges and agrees that Transmission Provider has no obligation under this Agreement to disclose to Consumers any information with respect to third-party developments or circumstances, including the identity or existence of any such person or other assets, beyond what Transmission Provider customarily provides to other similarly situated generators, except as may be required under Article 4 of this Agreement and elsewhere in this Agreement. Consumers and Transmission Provider make no guarantees to the other under this Agreement with respect to Transmission Service that is available under the MISO Tariff.

ARTICLE 4

INTERCONNECTION ASSETS

4.1Reservation of Rights to Interconnection Assets

Except as provided in Section 5.2 hereof, each Party reserves to itself the ownership, operation and maintenance of its Interconnection Assets and all improvements, additions or extensions to its Interconnection Assets under this Agreement which are attributable to or necessitated by the interconnection of the Unit.

4.2Modifications

Either Party may undertake modifications to its assets. In the event a Party plans to undertake a modification that may be expected to impact the other Party's assets, that Party shall provide the other Party with sufficient information regarding such modification, including, without limitation, the notice required in accordance with Article 11 of this Agreement so that the other Party can evaluate the potential impact of such modification prior to commencement of the work. The Party desiring to perform such work shall provide the relevant drawings, plans, and specifications to the other Party at least ninety (90) days in advance of commencement of the work or such shorter period upon which the Parties may agree, which agreement will not unreasonably be withheld or delayed.

4.3As-Built Drawings

Upon execution of this Agreement, Consumers shall provide to Transmission Provider and Transmission Owner current interconnection drawings and system diagrams for each of its Units, unless the Parties agree that such drawings are not necessary. Subject to the requirements of Article 17 of this Agreement, not later than ninety (90) days after completion of any addition to or modification of the assets of any of said Units that may reasonably be expected to affect the Transmission System, Consumers shall issue revised “as built” drawings to Transmission Provider and Transmission Owner.

ARTICLE 5

OPERATIONS

5.1General

The Parties agree that they shall comply with the Operating Agreement, then-existing (or amended) applicable manuals, standards, and guidelines of Transmission Provider, NERC, ECAR, or any successor agency assuming or charged with similar responsibilities related to the operation and reliability of the North American electric interconnected transmission grid. To the extent that this Agreement does not specifically address or provide the mechanisms necessary to comply with such Operating Agreement, Transmission Provider, NERC or ECAR manuals, standards, or guidelines, the Parties hereby agree that each Party shall provide to the other Parties all such information as may reasonably be required to comply with such Operating Agreement, manuals, standards, or guidelines and shall operate, or cause to be operated, their respective assets in accordance with such Operating Agreement, manuals, standards, or guidelines.

5.2 Transmission Provider and Transmission Owner Obligations

Transmission Provider and Transmission Owner shall operate and control the Transmission System and other Transmission Owner assets in a safe and reliable manner (a) in accordance with Transmission Provider’s and Transmission Owner’s applicable operational and/or reliability criteria, protocols, and directives (which include those of NERC and ECAR), (b) the Operating Agreement and (c) in accordance with the provisions of this Agreement. From time to time, Consumers will control and operate four (4) 345 kV synchronizing circuit breakers (Nos. 28H9, 28R8, 32F7 and 32H9 in the Hampton Substation) to connect or disconnect the Karn 3 or Karn 4 Units, as the case may be, from the Transmission System. The Parties may agree from time to time that Consumers, under the direction of the Transmission Provider or Transmission Owner, will operate certain other Interconnection Assets of the Transmission Owner.

5.3Consumers Obligations

Consumers shall operate and control its Generation Resources in a safe and reliable manner in accordance with (a) Consumers’ applicable operational and/or reliability criteria, protocols, and directives (which shall include those of NERC and ECAR), the Operating Agreement and (c) the provisions of this Agreement.

5.4Jointly Owned Assets

Operation of Jointly Owned Assets at the electric substations where Interconnection Facilities are located will be under the direction and control of the Party with more than fifty percent (50%) of the major equipment at each such location, unless otherwise agreed by the Parties hereto. Said

Party shall operate the Jointly Owned Assets in a manner consistent with Good Utility Practice and the provisions of Sections 5.2 and 5.3 above, as appropriate. Each Party’s respective share of responsibility for the costs of operation of Jointly Owned Assets shall be the same percentage as the percentage of major equipment owned by such Party in that substation, as set forth in Exhibit B and its subsequent addendum’s. The respective ownership of substation facilities is shown in the Wiring Diagrams for each of the electrical substations at which Consumers’ Generation Resources are connected to the Transmission System (see Exhibit B), reflecting ownership changes through July 24, 2008. The Wiring Diagrams (WDs) will be updated continuously in each Party’s Drawing Management System (DMS) which is shared between the Parties. For current ownership (reflecting ownership changes since July 24, 2008), see the WDs in the DMS. For purposes of this Agreement, major equipment is defined as (a) main power transformers, (b) 23 kV, 46 kV, 138 kV and 345 kV circuit breakers, (c) power system regulators and reclosers and (d) 46 kV and 138 kV capacitor banks (any three-phase installation of such equipment shall count as one unit of equipment). Exhibit B shall be updated with an addendum at least annually by the Transmission Owner, and approved in writing by all Parties at least annually, to show all changes in equipment and the effects of such changes on the determination of Jointly Owned Asset percentages. For purposes of this Section 5.4, such submission and approval of changes shall be in writing consistent with Section 21.1. In the case where each Party hereto owns exactly fifty percent (50%) of the major equipment at any specific location, the Transmission Owner shall assume the responsibility for direction and control of the operation activities as such location. In those substations where each Party hereto owns assets, each Party shall be responsible for its appropriate share, as set forth in Exhibit B hereto, of station power energy usage and expense.

5.5Access Rights

The Parties shall provide each other such access rights as may be necessary for either Party’s performance of its respective operational obligations under this Agreement; provided that, notwithstanding anything stated herein, a Party performing operational work within the boundaries of the other Party’s assets must abide by the rules applicable to that site.

5.6Switching and Tagging Rules

The Parties shall abide by their respective Switching and Tagging Rules for obtaining clearances for work or for switching operations on assets. The Parties will adopt mutually agreeable Switching and Tagging Rules prior to the effective date of this Agreement.

5.7 Black Start Participation

In accordance with Good Utility Practice, Consumers agrees to participate in Transmission Owner’s Black Start Plan, as well as any verification testing. Nothing in this Agreement obligates a particular Unit to provide Black Start Service.

5.8 Reactive Power

The supply and absorption of reactive power is dealt with in the Purchase and Sale Agreement for Ancillary Services among the Parties hereto.

5.9 System Security

During an Emergency on the Transmission System or on an adjacent transmission system, the System Operator has the authority to direct Consumers to increase or decrease real power production (measured in MW) and/or reactive power production (measured in MVAR), within the design and operational limitations of any of Consumers’ Generation Resources in service at the time, in order to maintain security on the Transmission System. In the event of such a declaration of an Emergency, determinations: (a) that the Transmission System security is in jeopardy, and/or (b) that there is a need to increase or decrease reactive power production, even if real power production is adversely affected, will be made solely by the System Operator or his designated representative. Each Unit operator will honor System Operator’s orders and directives concerning said Unit’s real power and/or reactive power output within design and operational limitations of the Unit’s equipment in service at the time, such that the security of the Transmission System is maintained. Transmission Provider and Transmission Owner shall restore the Transmission System conditions to normal to alleviate any such Emergency, in accordance with Good Utility Practice. Consumers will be compensated by Transmission Provider or Transmission Owner for increasing or decreasing the real power output of any of its Units as directed by the System Operator to support the Transmission System during an Emergency by the payment of (a) Consumers’ Incremental Cost associated with such increase or decrease in real power output or (b) at such other rate filed by a Party and approved by the Commission including any existing tariff or rate schedule which has been filed by the Transmission Provider, Transmission Owner or Consumers. Similarly, if the Transmission Provider or Transmission Owner requests any of Consumers’ Units to provide or absorb reactive power that would be outside of the Unit’s Reactive Design Limitations, requiring the Unit’s real power output to be reduced to obtain the desired reactive power, the Transmission Provider or Transmission Owner shall compensate Consumers at the real power rate discussed in the preceding sentence, to the extent that the Unit had to reduce real power output to operate within its Reactive Design Limitations, unless otherwise provided in another agreement or tariff on file with the Commission.

5.10Consumers Voltage Regulation

Consumers shall have sufficient voltage regulation at each Unit to maintain an acceptable voltage level for the equipment at the Unit during periods of time that the Unit’s generation is off line.

5.11Protection and System Quality

Consumers shall, at its expense, install, maintain, and operate System Protection Assets, including such protective and regulating devices as are identified by order, rule or regulation of any duly constituted regulatory authority having jurisdiction, or as are otherwise necessary to protect personnel and assets and to minimize deleterious effects to Transmission Provider’s or Transmission Owner’s electric service operation arising from the Unit. Transmission Owner shall install any such protective or regulating devices that may be required on Transmission Owner’s assets in connection with the operation of the Unit at Consumers’ expense.

5.11.1Requirements for Protection. In compliance with applicable NERC, ECAR and Transmission Provider’s and Transmission Owner’s requirements, Consumers shall provide, own, and maintain relays, circuit breakers and all other devices necessary to promptly remove any fault contribution of the Unit to any short circuit occurring on the Transmission System not otherwise

isolated by Transmission Owner’s assets. Such protective assets shall include, without limitation, a disconnecting device or switch with visible blade disconnect and load interrupting capability to be located between the Unit and the Transmission System at an accessible, protected, and satisfactory site selected upon mutual agreement of the Parties. The present integrated system provides for fault clearing at the generation substations. Unit protection may not be able to detect all short circuits, but the Parties agree that no other arrangements shall be required. Consumers shall be responsible for protection of the Unit and Consumers’ other associated assets from such conditions as negative sequence currents, over- or under-frequency, sudden load rejection, over- or under-voltage, and generator loss-of-field. Consumers shall be solely responsible for provisions to disconnect the Unit and Consumers’ other associated assets when any of the disturbances described above occur on the Transmission System.

5.11.2System Power Quality. Consumers’ facilities and equipment shall not cause excessive voltage flicker nor introduce excessive distortion to the sinusoidal voltage or current waves. Power output from and input to the Unit shall be in accordance with the power quality standards contained in IEEE Standards 141 - Recommended Practice for Electrical Power Distribution for Industrial Plants (voltage flicker) and 519 - Recommended Practices and Requirements for Harmonic Control in Electric Power Systems (harmonics). Consumers’ facilities and equipment have been designed and constructed in accordance with then-existing standards so as not to cause excessive voltage excursions nor cause the voltage to drop below or rise above the range maintained by Transmission Provider or Transmission Owner in the absence of Consumers’ facilities and equipment at the time the Unit first went into service.

5.11.3Inspection. Subject to the confidentiality provisions set forth in Article 17, Transmission Provider and Transmission Owner shall have the right, but shall have no obligation or responsibility to (a) observe Consumers’ tests and/or inspection of any of Consumers’ protective assets directly connected to the Transmission System or interfacing with Transmission Owner’s protective assets, (b) review the settings of any of Consumers’ protective assets; and (c) review Consumers’ maintenance records relative to Consumers’ protective assets. Transmission Provider and Transmission Owner may exercise the foregoing rights from time to time as deemed necessary by Transmission Provider or Transmission Owner upon reasonable notice to Consumers. However, the exercise or non-exercise by Transmission Provider or Transmission Owner of any of the foregoing rights of observation, review or inspection shall be construed neither as an endorsement or confirmation of any aspect, feature, element, or condition of the Unit or Consumers’ protective assets or the operation thereof, nor as a warranty as to the fitness, safety, desirability, or reliability of same.

5.12Outages, Interruptions, and Disconnection

5.12.1Outage Authority and Coordination. In accordance with Good Utility Practice, each Party may, in close cooperation with the other and upon providing notice per Section 20.2, remove from service its assets that may impact the other Party’s assets as necessary to perform maintenance or testing or to install or replace assets. Absent the existence or imminence of an Emergency, the Party scheduling a removal of a facility from service will schedule such removal on a date mutually acceptable to both Parties. Further, the Transmission Provider and Transmission Owner shall use their best efforts to coordinate the scheduling of maintenance on Transmission Owner’s Interconnection Assets to coincide with Consumers scheduled maintenance on its Units that may be impacted by maintenance on Transmission Owner’s Interconnection Assets.

5.12.2Outage Restoration.

5.12.2.1Unplanned Outage. In the event of an unplanned outage of a Party’s facility that adversely affects the other Party’s assets, the Party that owns or controls the facility out of service will use commercially reasonable efforts to promptly restore that facility to service.

5.12.2.2Planned Outage. In the event of a planned outage of a Party’s facility that adversely affects the other Party’s assets, the Party that owns or controls the facility out of service will use commercially reasonable efforts to promptly restore that facility to service and in accordance with its schedule for the work that necessitated the planned outage.

5.12.3Interruption. If at any time, in Transmission Provider’s or Transmission Owner’s reasonable judgment, the continued operation of the Unit would cause an Emergency, Transmission Provider or Transmission Owner may curtail, interrupt, or reduce energy delivered from the Unit to the Transmission System until the condition which would cause the Emergency is corrected. Transmission Provider or Transmission Owner shall give Consumers as much notice as is reasonably practicable of Transmission Provider’s or Transmission Owner’s intention to curtail, interrupt, or reduce energy delivery from the Unit in response to a condition that would cause an Emergency and, where practicable, allow suitable time for the Parties to remove or remedy such condition before any such curtailment, interruption, or reduction commences. In the event of any curtailment, interruption, or reduction, Transmission Provider or Transmission Owner shall promptly confer with Consumers regarding the conditions that gave rise to the curtailment, interruption, or reduction, and Transmission Provider or Transmission Owner shall give Consumers Transmission Provider’s or Transmission Owner’s recommendation, if any, concerning the timely correction of such conditions. Transmission Provider or Transmission Owner shall promptly cease the curtailment, interruption, or reduction of energy delivery when the condition that would cause the Emergency ceases to exist.

5.12.4Disconnection.

5.12.4.1Disconnection after Agreement Terminates. Upon termination of the Agreement, Transmission Provider or Transmission Owner may disconnect Consumers’ Generation Resources from the Transmission System in accordance with a plan for disconnection upon which the Parties agree.

5.12.4.2Disconnection in Event of Emergency. Subject to the provisions of Subsection 5.12.4.3 of this Agreement, Transmission Provider, Transmission Owner or Consumers shall have the right to disconnect the Unit without notice if, in Transmission Provider’s, Transmission Owner’s or Consumers’ sole opinion, an Emergency exists and immediate disconnection is necessary to protect persons or property from damage or interference caused by Consumers’ interconnection or lack of proper or properly operating protective devices. For purposes of this Subsection 5.12.4.2, protective devices may be deemed by Transmission Provider or Transmission Owner to be not properly operating if Transmission Provider’s or Transmission Owner’s review under Article 6 of this Agreement has disclosed irregular or otherwise insufficient maintenance on such devices or that maintenance records do not exist or are otherwise insufficient to demonstrate that adequate maintenance has been and is being performed.

5.12.4.3Disconnection after Under-frequency Load Shed Event. NERC Planning Criteria require the interconnected transmission system frequency be maintained between 59.95 Hz and 60.05 Hz. In case of an under-frequency system disturbance, the Transmission System is designed to automatically activate a five-tier load shed program. The five load sheds occur at 59.5, 59.3, 59.1, 58.9 and 58.7 Hz, respectively. For those Units that are determined by Transmission Provider to be large enough to impact the Transmission Provider’s system security, each such Unit shall be capable of under-frequency operation as specified in Appendix 1 “Isolation of Generating Units” contained in ECAR Document No. 3 - Emergency Operations, or a higher under-frequency set point if already in place upon execution of this Agreement. Upon notice from Consumers and if the Transmission Provider or Transmission Owner agrees, Consumers may implement a higher under-frequency relay set point if necessary to protect its assets for a particular Unit or Units.

5.12.5Continuity of Service. Notwithstanding any other provision of this Agreement, Transmission Provider shall not be obligated to accept, and Transmission Provider may require Consumers to curtail, interrupt or reduce deliveries of energy if such delivery of energy impairs Transmission Provider’s or Transmission Owner’s ability to construct, install, repair, replace or remove any of its equipment or any part to its system or if Transmission Provider or Transmission Owner determines that curtailment, interruption or reduction is necessary because of Emergencies, forced outages, operating conditions on its system, or any reason otherwise permitted by applicable rules or regulations promulgated by a regulatory agency having jurisdiction over such matters. The Parties shall coordinate, and if necessary negotiate in good faith, the timing of such curtailments, interruptions, reductions or deliveries with respect to maintenance, investigation or inspection of Transmission Owner’s assets or system. Consumers reserves all rights under the Federal Power Act and applicable other federal and state laws and regulations to commence a complaint proceeding or other action with the Commission or other Governmental Authority with appropriate jurisdiction over the Parties to enforce the provisions of this Subsection 5.12.5.

5.12.6Curtailment Notice. Except in case of Emergency, in order not to interfere unreasonably with the other Party’s operations, the curtailing, interrupting or reducing Party shall give the other Party reasonable prior notice of any curtailment, interruption or reduction, the reason for its occurrence, and its probable duration.

5.13Operating Expenses

Consumers shall reimburse Transmission Owner for all direct and indirect costs and expenses (including but not limited to telephone circuit charges, property taxes, insurance and assets testing) incurred by Transmission Owner in operating Transmission Owner’s Interconnection Assets, to the extent that Transmission Owner is not otherwise recovering such costs and expenses under an existing tariff or rate schedule which has been filed by Transmission Provider or Transmission Owner and accepted by FERC. Such costs and expenses shall be determined by Transmission Owner in accordance with the standard practices and policies followed by Transmission Provider or Transmission Owner for the performance of work for others in effect at the time such operation work is performed. Payment by Consumers shall be made in accordance with the provisions of Article 12 hereof.

ARTICLE 6

MAINTENANCE

6.1Transmission Owner’s Obligations

Transmission Owner shall maintain its assets, to the extent they might reasonably be expected to have an impact on the operation of the Unit (a) in a safe and reliable manner in accordance with applicable operational and/or reliability criteria, protocols, and directives (which include those of NERC and ECAR), (b) in accordance with the provisions of the Operating Agreement and (c) in accordance with the provisions of this Agreement.

6.2Consumers’ Obligations

Consumers shall maintain its assets, to the extent they might reasonably be expected to have an impact on the operation of the Transmission System (a) in a safe and reliable manner in accordance with applicable operational and/or reliability criteria, protocols, and directives (which include those of NERC and ECAR), (b) in accordance with the provisions of the Operating Agreement and (c) in accordance with the provisions of this Agreement.

6.3Jointly Owned Assets

Maintenance of Jointly Owned Assets at the electric substations where Interconnection Facilities are located will be under the direction and control of the Party with more than fifty percent (50%) of the major equipment at each such location, unless otherwise agreed by the Parties hereto. Said Party shall maintain the Jointly Owned Assets in a manner consistent with Good Utility Practice and the provisions of Sections 6.1 and 6.2 above, as appropriate. Each Party’s respective share of responsibility for the costs of maintenance of Jointly Owned Assets shall be the same percentage as the percentage of major equipment owned by such Party in that substation, as set forth in Exhibit B and its subsequent addendum. For purposes of this Agreement, major equipment is defined as set forth in Section 5.4 hereto. Exhibit B shall be updated with an addendum at least annually by the Transmission Owner, and approved in writing by Consumers, to show all changes in equipment and the effects of such changes on the determination of Jointly Owned Asset percentages. In the case where each Party hereto owns exactly fifty percent (50%) of the major equipment at any specific location, the Transmission Owner shall assume the responsibility for direction and control of the maintenance activities at such location.

6.4Access Rights

The Parties shall provide each other such access rights as may be necessary for either Party’s performance of their respective maintenance and/or construction obligations under this Agreement; provided that, notwithstanding anything stated herein, a Party performing maintenance and/or construction work within the boundaries of the other Party’s assets must abide by the rules applicable to that site.

6.5Maintenance Expenses

Consumers shall reimburse Transmission Owner for all direct and indirect costs and expenses (including but not limited to inspection, repair and replacement) incurred by Transmission Owner in maintaining Transmission Owner’s Interconnection Assets, to the extent that Transmission

Owner is not otherwise recovering such costs and expenses under an existing tariff or rate schedule which has been filed by Transmission Provider or Transmission Owner and accepted by FERC. Such costs and expenses shall be determined by Transmission Owner in accordance with the standard practices and policies followed by Transmission Provider or Transmission Owner for the performance of work for others in effect at the time such operation work is performed. Payment by Consumers shall be made in accordance with the provisions of Article 12 of this Agreement.

6.6Coordination

The Parties agree to confer regularly to coordinate the planning and scheduling of preventative and corrective maintenance. Each Party shall conduct preventive and corrective maintenance activities as planned and scheduled in accordance with this Section 6.5 and the Operating Agreement.

6.7Inspections and Testing

Each Party shall perform routine inspection and testing of its assets in accordance with Good Utility Practice as may be necessary to ensure the continued interconnection of each Unit with the Transmission System in a safe and reliable manner.

6.8Right to Observe Testing

Each Party shall, at its own expense, have the right to observe the testing of any of the other Party’s assets whose performance may reasonably be expected to affect the reliability of the observing Party’s assets. Each Party shall notify the other Party in advance of its performance of tests of its assets, and the other Party may have a representative attend and be present during such testing.

6.9Secondary Systems

Each Party agrees to cooperate with the other in the inspection, maintenance, and testing of those Secondary Systems directly affecting the operation of a Party’s assets which may reasonably be expected to impact the other Party. Each Party will provide advance notice to the other Party before undertaking any work in these areas, especially in electrical circuits involving circuit breaker trip and close contacts, current transformers, or potential transformers.

6.10Observation of Deficiencies

If a Party observes any deficiencies or defects on, or becomes aware of a lack of scheduled maintenance and testing with respect to, the other Party’s assets that might reasonably be expected to adversely affect the observing Party’s assets, the observing Party shall either (a) provide notice to the other Party that is prompt under the circumstance or (b) deem such observation an Emergency to life or property and immediately disconnect the Unit pursuant to Subsection 5.12.4.2 of this Agreement, and the other Party shall make any corrections required in accordance with Good Utility Practice.

ARTICLE 7

EMERGENCIES

7.1Obligations

Each Party agrees to comply with NERC and ECAR Emergency procedures and Transmission Provider, Transmission Owner and Consumers Emergency procedures, as applicable, with respect to Emergencies.

7.2Notice

Transmission Provider or Transmission Owner shall provide Consumers with oral notification that is prompt under the circumstances of an Emergency that may reasonably be expected to affect Consumers’ operation of any or all of its Generation Resources, to the extent Transmission Provider or Transmission Owner is aware of the Emergency. Consumers shall provide Transmission Provider and Transmission Owner with oral notification that is prompt under the circumstances of an Emergency that may reasonably be expected to affect the Transmission System, to the extent Consumers is aware of the Emergency. In lieu of oral notification described in the preceding two sentences, the Parties may agree in advance to use other electronic notification means. To the extent the Party becoming aware of an Emergency is aware of the facts of the Emergency, such notification shall describe the Emergency, the extent of the damage or deficiency, its anticipated duration, and the corrective action taken and/or to be taken. Any such notification given pursuant to this Section 7.2 shall be followed as soon as practicable with written notice.

7.3Immediate Action

In case of an Emergency, the Party becoming aware of the Emergency may, in accordance with Good Utility Practice, take such action as is reasonable and necessary to prevent, avoid, or mitigate injury, danger, and loss, including disconnection pursuant to Subsection 5.12.4.2 of this Agreement.

7.4Transmission Provider’s and Transmission Owner’s Authority

Transmission Provider or Transmission Owner may, consistent with Good Utility Practice, take whatever actions with regard to the Transmission System as it may deem necessary during an Emergency in order to (a) preserve public health and safety, (b) preserve the reliability of the Transmission System, (c) limit or prevent damage and (d) expedite restoration of service. Transmission Provider or Transmission Owner shall use reasonable efforts to minimize the effect of such actions on the Unit.

7.5Consumers’ Authority

Consumers may, consistent with Good Utility Practice, take whatever actions with regard to the Unit as it may deem necessary during an Emergency in order to (a) preserve public health and safety, (b) preserve the reliability of the Unit, (c) limit or prevent damage and (d) expedite restoration of service. Consumers shall use reasonable efforts to minimize the effect of such actions on the Transmission System.

7.6Audit Rights

Each Party shall keep and maintain records of actions taken during an Emergency that may reasonably be expected to impact the other Party’s assets and make such records available for third-party independent audit upon the request and expense of the party affected by such action. Any such request for an audit will be no later than twelve (12) months following the action taken.

ARTICLE 8

SAFETY

8.1General

The Parties agree that all work performed by a Party that may reasonably be expected to affect another Party shall be performed in accordance with Good Utility Practice and all applicable laws, regulations, and other requirements pertaining to the safety of persons or property. A Party performing work within the boundaries of another Party’s assets must abide by the safety rules applicable to the site.

8.2Environmental Releases

Each Party shall notify the other Parties, first orally and then in writing, of the release of any Hazardous Substances or any type of remedial activities, such as asbestos or lead abatement, which may reasonably be expected to affect another Party, as soon as possible but not later than twenty-four (24) hours after the Party becomes aware of the occurrence, and shall promptly furnish to the other Parties copies of any reports filed with any governmental agencies addressing such events.

ARTICLE 9

METERING

9.1General

Transmission Owner shall provide, install, own and maintain Metering Assets necessary to meet its obligations under this Agreement. Notwithstanding the foregoing sentence, Consumers, if mutually agreed by the Parties, may provide and install some, or all, of said Metering Assets, as per Transmission Owner’s specifications. The Parties agree that, as to all Connection Points in existence as of the effective date of this Agreement, no new Metering Assets or arrangements shall be required. If necessary, Metering Assets shall be either located or adjusted, at Transmission Provider’s or Transmission Owner’s option, in such manner to account for (a) any transformation or interconnection losses between the location of the meter and the Point of Receipt and (b) any station auxiliary power load of the generating unit. Metering quantities, in analog and/or digital form, shall be provided to Consumers upon request. The Parties also agree that Consumers shall continue to maintain records of the Megawatthour and Megavarhour values collected from existing meters on the generating units and provide the information recorded to Transmission Provider or Transmission Owner upon request.

9.2Costs of Administering Metering Assets

All costs associated with the administration of Metering Assets and the provision of metering data to Consumers shall be born by Consumers. The costs of administration and of providing metering data shall be separately itemized on Transmission Owner’s invoices to Consumers pursuant to Article 12 of this Agreement. All costs associated with changes to Metering Assets requested by Consumers, shall be borne by Consumers and shall be invoiced pursuant to Article 12 of this Agreement.

9.3Testing of Metering Assets

Transmission Owner shall, at Consumers’ expense, inspect and test all Metering Assets not less than once every year, unless an extension of the testing cycle is agreed upon by the Parties. If requested to do so by Consumers and at Consumers’ expense, Transmission Owner shall inspect or test Metering Assets more frequently. Transmission Owner shall give reasonable notice of the time when any inspection or test shall take place and Consumers may have representatives present at the test or inspection. If Metering Assets is found to be inaccurate or defective, it shall be adjusted, repaired or replaced at Consumers’ expense, in order to provide accurate metering. If Metering Assets fails to register, or if the measurement made by Metering Assets during a test varies by more than two percent (2%) from the measurement made by the standard Metering Assets used in the test, adjustment shall be made correcting all measurements made by the inaccurate Metering Assets for (a) the actual period during which inaccurate measurements were made, if the period can be determined, or (b) a period equal to one-half of the elapsed time since the last test of the Metering Assets.

9.4Metering Data

9.4.1When the Metering Assets location is not at the Point of Receipt, Metering Assets readings shall be adjusted to account for appropriate transformer and line losses, and when applicable, the station auxiliary power load of the Unit.

9.4.2At Consumers’ expense, all metered data shall be telemetered to one or more locations designated by Transmission Provider and one or more locations designated by Consumers.

9.5Communications

9.5.1At Consumers’ expense, Consumers shall maintain satisfactory operating communications with System Operator or representative, as designated by Transmission Provider or Transmission Owner. Consumers has provided standard voice and facsimile communications in the control room of each of its Units through use of the public telephone system. Consumers has also provided a 4-wire, full duplex data circuit (or circuits) operating at a minimum of 9600 baud, or at other baud rates as reasonably specified by Transmission Provider or Transmission Owner. The data circuit(s) extend from each Consumers’ Unit to a location, or locations, specified by Transmission Provider or Transmission Owner. Any required maintenance of such communications assets shall be performed at Consumers’ expense, and may be performed by Consumers or by Transmission Owner. Operational communications shall be activated and maintained under, but not be limited to, the following events: system paralleling or separation,

scheduled and unscheduled shutdowns, equipment clearances, and hourly and daily load data exchanges. To the extent required by applicable rules and regulations, Consumers shall (a) request permission from the System Operator prior to opening or closing circuit breakers that affect the Transmission System, (b) carry out switching orders from the System Operator in a timely manner and (c) keep the System Operator advised of the Unit’s operational capabilities as required for reliable operation of the Transmission System.

9.5.2For all Units 1 MW or larger, a Remote Terminal Unit (”RTU”), or equivalent data collection and transfer equipment acceptable to Consumers and Transmission Owner, has been installed to gather accumulated and instantaneous data to be telemetered to a location, or locations, designated by Transmission Owner through use of dedicated point-to-point data circuits as indicated in Subsection 9.5.1 of this Agreement. Instantaneous bi-directional analog real power and reactive power flow information, circuit breaker status information, instantaneous analog voltage information, metering information, and disturbance monitoring information, as determined by Transmission Provider or Transmission Owner, must be telemetered directly to the location, or locations, specified by Transmission Provider or Transmission Owner.

ARTICLE 10

FORCE MAJEURE

10.1An event of Force Majeure means any act of God, labor disturbance, act of the public enemy, war, insurrection, riot, fire, storm or flood, explosion, breakage or accident to machinery or assets, any curtailment, order, regulation or restriction imposed by governmental military or lawfully established civilian authorities, or any other cause beyond a Party’s reasonable control. A Force Majeure event does not include an act of negligence or intentional wrongdoing.

10.2If either Party is rendered unable, wholly or in part, by Force Majeure, to carry out its obligations under this Agreement, then, during the continuance of such inability, the obligation of such Party shall be suspended except that Consumers’ obligation under Section 5.11 of this Agreement to provide protection while operating in parallel with the Transmission System shall not be suspended. The Party relying on Force Majeure shall give written notice of Force Majeure to the other Party as soon as practicable after such event occurs. Upon the conclusion of Force Majeure, the Party heretofore relying on Force Majeure shall, with all reasonable dispatch, take all necessary steps to resume the obligation previously suspended.

10.3Any Party’s obligation to make payments already owing shall not be suspended by Force Majeure.

ARTICLE 11

INFORMATION REPORTING

Each Party shall, in accordance with Good Utility Practice, promptly provide to the other Parties all relevant information, documents, or data regarding the Party’s assets which may reasonably be expected to pertain to the reliability of the other Parties’ assets and/or which has been reasonably requested by the other Parties.

ARTICLE 12

PAYMENTS AND BILLING PROCEDURES

12.1Invoices

Any invoices for reimbursable services provided to another Party under this Agreement during the preceding month shall be prepared within a reasonable time after the first day of each month. Each invoice shall delineate the month in which services were provided, shall fully describe the services rendered and shall be itemized to reflect the services performed or provided. The invoice shall be paid so that the other Party will receive the funds by the 20^th day following the date of such invoice, or the first business day thereafter if the payment date falls on other than a business day. All payments shall be made in immediately available funds payable to another Party, or by wire transfer to a bank named by the Party being paid, provided that payments expressly required by this Agreement to be mailed shall be mailed in accordance with Section 12.2.

12.2Payments

Any payments to be made by Consumers under this Agreement shall be made to Transmission Owner at the following address:

Michigan Electric Transmission Company, LLC

P.O. Box 673971

Detroit, MI 48267-3971

Attn: Accounting Department

If paying by wire transfer, please see the wiring instructions on the invoice.

Any payments to be made by Transmission Owner under this Agreement shall be made to Consumers at the following address:

Consumers Energy Company

One Energy Plaza

Jackson, Michigan 49201

Attn: Treasurer

The Parties shall provide the names of appropriate contact personnel, as are set forth in this Agreement or otherwise, to each other after this Agreement is executed and shall keep said listing of names and addresses up to date.

12.3Interest Charges

Interest on any unpaid amounts shall be calculated in accordance with the methodology specified for interest on refunds in the Commission’s regulations at 18 CFR. §35.19 (a)(2)(iii). Interest on delinquent amounts shall be calculated from the due date of the invoice to the date of payment. When payments are made by mail, invoices shall be considered as having been paid on the date of receipt by Transmission Owner or Consumers, as the case may be.

12.4Disputes

In the event of a billing dispute between Transmission Owner and Consumers, the Parties shall continue to provide services and pay all invoiced amounts not in dispute. While the dispute is being resolved, the Parties shall continue to provide services and pay all invoiced amounts not in dispute. Following resolution of the dispute, the prevailing Party shall be entitled to receive the disputed amount, as finally determined to be payable, along with interest accrued through the date on which payment is made at the interest rate pursuant to Section 13.3. Payment shall be due within ten (10) days of resolution.

ARTICLE 13

ASSIGNMENT

13.1This Agreement shall inure to the benefit of and be binding upon the successors and assigns of the respective parties hereto. This Agreement shall not be transferred or otherwise alienated by any Party without the other Parties’ prior written consent, which consent shall not be unreasonably withheld, provided that any assignee shall expressly assume assignor’s obligations hereunder and, unless expressly agreed to by the other Parties, no assignment shall relieve the assignor of its obligations hereunder in the event its assignee fails to perform. Any attempted assignment, transfer or other alienation without such consent shall be void and not merely voidable.

13.2Notwithstanding the above, the Transmission Provider or Transmission Owner shall be permitted to assign or otherwise transfer this Agreement, or its rights, duties and obligations hereunder, in whole or in part, by operation of law or otherwise, without the prior written consent of Consumers, to any successor to or transferee of the direct or indirect ownership or operation of all or part of the transmission system to which the Generation Resources are connected. Upon the assumption by any such permitted assignee of the assigning Transmission Provider’s or Transmission Owner’s rights, duties and obligations hereunder, the assigning Transmission Provider or Transmission Owner shall be released and discharged therefrom to the extent provided in the assignment agreement.

13.3Notwithstanding the above, Consumers may assign this Agreement to a bank pursuant to the terms of an Assignment and Security Agreement without the prior written consent of Transmission Provider or Transmission Owner provided that such assignment shall not be effective as to Transmission Provider or Transmission Owner until it receives a fully executed copy thereof.

ARTICLE 14

INDEMNITY AND INSURANCE

14.1Indemnity

The Parties shall at all times assume all liability for, and shall indemnify and save the other Parties harmless from any and all damages, losses, claims, demands, suits, recoveries, costs, legal fees, expenses for injury to or death of any person or persons whomsoever, or for any loss, destruction of or damage to any property of third persons, firms, corporations or other entities that occurs on its own system and that arises out of or results from, either directly or indirectly, its own assets or assets controlled by it, unless caused by the sole negligence, or intentional wrongdoing, of another Party.

14.2Insurance

14.2.1The Parties agree to maintain, at their own cost and expense, the following insurance coverages for the life of this Agreement in the manner and amounts, at a minimum, as set forth below:

(a)Workers' Compensation Insurance in accordance with all applicable State, Federal, and Maritime Law.

(b)Employer's Liability insurance in the amount of $1,000,000 per accident.

(c)Commercial General Liability or Excess Liability Insurance in the amount of $25,000,000 per occurrence.

(d)Automobile Liability Insurance for all owned, non-owned, and hired vehicles in the amount of $5,000,000 each accident.

14.2.2A Party may, at its option, [A] be an approved self-insurer for the insurances required in 1.(a) and (d); and [B] maintain such deductibles and/or retentions under the insurance required in 1.(b) and (c) as is maintained by other similarly situated companies engaged in a similar business. The Parties agree that all amounts of self-insurance, retentions and/or deductibles are the responsibility of, and shall be borne by, the Party whom makes such an election.

14.2.3Within fifteen (15) days of the Effective Date and thereafter when requested, in writing, but not more than once every 12 months, during the term of this Agreement (including any extensions) each Party shall provide to the other Parties properly executed and current certificates of insurance or evidence of approved self-insurance status with respect to all insurance required to be maintained by such Party under this Agreement. Certificates of insurance shall provide the following information:

(a)Name of insurance company, policy number and expiration date.

(b)The coverage maintained and the limits on each, including the amount of deductibles or retentions, which shall be for the account of the Party maintaining such policy.

(c)The insurance company shall endeavor to provide thirty (30) days prior written notice of cancellation to the certificate holder.

ARTICLE 15

LIMITATION ON LIABILITY

NO PARTY SHALL IN ANY EVENT BE LIABLE TO THE OTHER PARTIES FOR ANY SPECIAL, INCIDENTAL, EXEMPLARY, PUNITIVE OR CONSEQUENTIAL DAMAGES SUCH AS, BUT NOT LIMITED TO, LOST PROFITS, REVENUE OR GOOD WILL, INTEREST, LOSS BY REASON OF SHUTDOWN OR NON-OPERATION OF EQUIPMENT OR MACHINERY, INCREASED EXPENSE OF OPERATION OF EQUIPMENT OR MACHINERY, COST OF PURCHASED OR REPLACEMENT POWER OR SERVICES OR CLAIMS BY CUSTOMERS, WHETHER SUCH LOSS IS BASED ON CONTRACT, WARRANTY, NEGLIGENCE, STRICT LIABILITY OR OTHERWISE.

ARTICLE 16

BREACH, CURE AND DEFAULT

16.1General

A breach of this Agreement (”Breach”) shall occur upon the failure by a Party to perform or observe any material term or condition of this Agreement. Default of this Agreement (”Default”) shall occur upon the failure of a Party in Breach of this Agreement to cure such Breach in accordance with the provisions of Section 16.4 of this Agreement.

16.2Events of Breach

A Breach of this Agreement shall include:

16.2.1The failure to pay any amount when due;

16.2.2The failure to comply with any material term or condition of this Agreement, including but not limited to any material Breach of a representation, warranty or covenant made in this Agreement;

16.2.3If a Party: (a) becomes insolvent; (b) files a voluntary petition in bankruptcy under any provision of any federal or state bankruptcy law or shall consent to the filing of any bankruptcy or reorganization petition against it under any similar law; (c) makes a general assignment for the benefit of its creditors or (d) consents to the appointment of a receiver, trustee or liquidator;

16.2.4Assignment of this Agreement in a manner inconsistent with the terms of this Agreement;

16.2.5Failure of a Party to provide such access rights, or a Party’s attempt to revoke or terminate such access rights, as provided under this Agreement; or

16.2.6Failure of a Party to provide information or data to the other Parties as required under this Agreement, provided the Party entitled to the information or data under this Agreement requires such information or data to satisfy its obligations under this Agreement.

16.3Continued Operation

In the event of a Breach or Default by a Party, the Parties shall continue to operate and maintain, as applicable, such DC power systems, protection and Metering Assets, Telemetering Assets, SCADA equipment, transformers, Secondary Systems, communications assets, building assets, software, documentation, structural components, and other assets and appurtenances that are reasonably necessary for Transmission Provider or Transmission Owner to operate and maintain the Transmission System and for Consumers to operate and maintain the Unit, in a safe and reliable manner.

16.4Cure and Default

Upon the occurrence of an event of Breach, the Party or Parties not in Breach (hereinafter the “Non-Breaching Party”), when it becomes aware of the Breach, shall give written notice of the Breach to the Breaching Party and to any other person the Parties to this Agreement identify in

writing to the other Parties in advance. Such notice shall set forth, in reasonable detail, the nature of the Breach, and where known and applicable, the steps necessary to cure such Breach. Upon receiving written notice of the Breach hereunder, the Breaching Party shall have thirty (30) days to cure such Breach. If the Breach is such that it cannot be cured within thirty (30) days, the Breaching Party will commence in good faith all steps as are reasonable and appropriate to cure the Breach within such thirty (30) day time period and thereafter diligently pursue such action to completion. In the event the Breaching Party fails to cure the Breach, or to commence reasonable and appropriate steps to cure the Breach, within thirty (30) days of becoming aware of the Breach; the Breaching Party will be in Default of the Agreement.

16.5Right to Compel Performance

Notwithstanding the foregoing, upon the occurrence of an event of Default, the non-Defaulting Party or Parties shall be entitled to: (a) commence an action to require the Defaulting Party to remedy such Default and specifically perform its duties and obligations hereunder in accordance with the terms and conditions hereof and (b) exercise such other rights and remedies as it may have in equity or at law.

ARTICLE 17

CONFIDENTIALITY

17.1All information regarding a Party (the “Disclosing Party”) that is furnished directly or indirectly to the another Party (the “Recipient”) pursuant to this Agreement and marked “Confidential” shall be deemed “Confidential Information”. Notwithstanding the foregoing, Confidential Information does not include information that (i) is rightfully received by Recipient from a third party having an obligation of confidence to the Disclosing Party, (ii) is or becomes in the public domain through no action on Recipient’s part in violation of this Agreement, (iii) is already known by Recipient as of the date hereof, or (iv) is developed by Recipient independent of any Confidential Information of the Disclosing Party. Information that is specific as to certain data shall not be deemed to be in the public domain merely because such information is embraced by more general disclosure in the public domain.

17.1.1Recipient shall keep all Confidential Information strictly confidential and not disclose any Confidential Information to any third party for a period of two (2) years from the date the Confidential Information was received by Recipient, except as otherwise provided herein.

17.1.2Recipient may disclose the Confidential Information to its affiliates and its affiliates’ respective directors, officers, employees, consultants, advisors, and agents who need to know the Confidential Information for the purpose of assisting Recipient with respect to its obligations under this Agreement. Recipient shall inform all such parties, in advance, of the confidential nature of the Confidential Information. Recipient shall cause such parties to comply with the requirements of this Agreement and shall be responsible for the actions, uses, and disclosures of all such parties.

17.1.3If Recipient becomes legally compelled or required to disclose any of the Confidential Information (including, without limitation, pursuant to the policies, methods, and procedures of the FERC, including the OASIS Standards of Conduct, or other Regulatory Authority), Recipient will provide the Disclosing Party with prompt written notice thereof so that the Disclosing Party may seek a protective order or other appropriate remedy. Recipient will furnish only that portion of the Confidential Information which its counsel considers legally required, and Recipient will cooperate,

at the Disclosing Party’s expense, with the Disclosing Party’s counsel to enable the Disclosing Party to obtain a protective order or other reliable assurance that confidential treatment will be accorded the Confidential Information. It is further agreed that, if, in the absence of a protective order, Recipient is nonetheless required to disclose any Confidential Information, Recipient will furnish only that portion of the Confidential Information which its counsel considers legally required.

ARTICLE 18

AUDIT RIGHTS

Subject to the requirements of confidentiality under Article 17 of this Agreement, each Party shall have the right, during normal business hours, and upon prior reasonable notice to another Party, to audit one another’s accounts and records pertaining to the Party’s performance and/or satisfaction of obligations arising under this Agreement. Said audit shall be performed at the offices where such accounts and records are maintained and shall be limited to those portions of such accounts and records that relate to obligations under this Agreement.

ARTICLE 19

DISPUTES

The Dispute Resolution Procedures set forth in the MISO Tariff shall apply to all disputes arising under this Agreement.

ARTICLE 20

NOTICES

20.1Any notice, demand or request required or permitted to be given by a Party to another and any instrument required or permitted to be tendered or delivered by a Party to another may be so given, tendered or delivered, as the case may be, by depositing the same in any United States Post Office with postage prepaid, for transmission by certified or registered mail, addressed to the Party, or personally delivered to the Party, at the address set out below:

To Transmission Owner:

Michigan Electric Transmission Company, LLC

27175 Energy Way

Novi, MI 48377

Attn: Legal Department - Contracts

To Consumers:

Consumers Energy Company

1945 W. Parnall Road

Jackson, Michigan 49201

Attn: Director of Staff - Generation

To Transmission Provider:

Midwest Independent Transmission System Operator, Inc.

Attn: Manager, Interconnection Planning

701 City Center Drive

Carmel, IN 46032

20.2The Parties shall use standard telephone circuits as the primary communication link for generation dispatch communications, including with respect to dispatching energy in the event of an Emergency and declaring unit capability. The Parties shall provide the names and telephone numbers of appropriate contact personnel, as are set forth in this Agreement or otherwise, to each other after this Agreement is executed and shall keep said listing of names and telephone numbers up to date.

ARTICLE 21

MISCELLANEOUS

21.1Amendments

This Agreement may be amended by and only by a written instrument duly executed by the Parties hereto. No change or modification as to any of the provisions hereof shall be binding on any Party unless approved in writing and approved by the duly authorized officers of the Parties. Notwithstanding the foregoing, nothing contained herein shall be construed as affecting in any way the right of Transmission Provider, Transmission Owner or Consumers to unilaterally make application to the Commission for a change in rates, terms or conditions of service under Sections 205 and 206 of the Federal Power Act and pursuant to the Commission’s Rules and Regulations promulgated thereunder. Transmission Provider reserves the right to file rate schedules with the Commission concerning any services Transmission Provider deems necessary for reliable and orderly bulk power system management, including but not limited to any standby or related services that may arise from a failure by Consumers to meet its schedule of deliveries across the assets covered by this Agreement.

21.2Binding Effect

This Agreement and the rights and obligations hereof, shall be binding upon and shall inure to the benefit of the successors and assigns of the Parties hereto.

21.3Counterparts

This Agreement may be executed in any number of counterparts, and each executed counterpart shall have the same force and effect as an original instrument.

21.4Entire Agreement

This Agreement constitutes the entire agreement among the Parties hereto with reference to the subject matter hereof and its execution superseded all previous agreements, discussions, communications and correspondence with respect to said subject matter. The terms and conditions of this Agreement and every Exhibit referred to herein shall be amended, as mutually agreed to by the Parties, to comply with changes or alterations made necessary by a valid applicable order of

any governmental regulatory authority, or any court, having jurisdiction hereof.

21.5Governing Law

The validity, interpretation and performance of this Agreement and each of its provisions shall be governed by the applicable laws of the State of Michigan, exclusive of its conflict of laws principles.

21.6Headings Not To Affect Meaning

The descriptive headings of the various Articles and Sections of this Agreement have been inserted for convenience of reference only and shall in no way modify or restrict any of the terms and provisions hereof.

21.7Waivers

Any waiver at any time by a Party of its rights with respect to a default under this Agreement, or with respect to any other matters arising in connection with this Agreement, shall not be deemed a waiver or continuing waiver with respect to any subsequent default or other matter.

21.8 Termination of Predecessor Interconnection Agreement

On the Effective Date, the August 1, 2011 Amendment and Restatement of the Generator Interconnection Agreement between Transmission Provider, Transmission Owner and Consumers shall terminate and be replaced by this Agreement with regard to the Units covered by this Agreement, except insofar as necessary to resolve billing and related matters arising from service rendered and other events occurring before the Effective Date.

IN WITNESS WHEREOF, the Parties hereto have caused this Agreement to be duly executed by their duly authorized officers.

MICHIGAN ELECTRIC TRANSMISSION COMPANY, LLC

By: ITC Holdings Corp., its manager

By _/s/ Gregory Ioanidis_________

Title _Vice President____________

CONSUMERS ENERGY COMPANY

By _/s/ David B. Kehoe___________

Title Director of Staff - Electric Generation

MIDWEST INDEPENDENT TRANSMISSION SYSTEM OPERATOR, INC.

By: /s/ William C. Phillips

Title: Vice President, Standards, Compliance and StrategyCampbell 1	312	260	260	16	3,600	Hydrogen	Yes	3	No	199
Campbell 2	492	355	360	20	3,600	Water/Hydrogen	Yes	3	No	299
Campbell A	21.9	13	17	13.8	3,600	Air	No	—	No	C16	Mothballed until February 2015.
Cobb 1	81.2	61	61	14.4	3,600	Hydrogen	No	—	No	199	Mothballed until April 2013.
Cobb 2	81.2	61	61	14.4	3,600	Hydrogen	No	—	No	299	Mothballed until April 2013.
Cobb 3	81.2	61	61	14.4	3,600	Hydrogen	No	—	No	399	Mothballed until April 2013.
Cobb 4	184	158	160	18	3,600	Hydrogen	Yes	1	No	499
Cobb 5	184	158	160	18	3,600	Hydrogen	Yes	1	No	599
Gaylord 1	18.8	14	17	13.8	3,600	Air	No	—	No	116
Gaylord 2	18.8	14	17	13.8	3,600	Air	No	—	No	216
Gaylord 3	18.8	14	17	13.8	3,600	Air	No	—	No	316
Gaylord 4	18.8	14	17	13.8	3,600	Air	No	—	No	416	Extended maintenance outage. Return to service December 2012.
Gaylord 5	21.9	14	17	13.8	3,600	Air	No	—	No	516	Retired on 10/15/2011
Karn 1	336	255	255	16	3,600	Hydrogen	Yes	3	No	199
Karn 2	320	260	260	16	3,600	Hydrogen	Yes	3	No	299
Karn 3	814.7	638	638	26	3,600	Water/Hydrogen	Yes	6	No	28R8/28H9	AGC Ramp Rate: 6 is avg. 9 Mw/min 60 thr. 500 Mw, 3 Mw/min 500 thr. 580 Mw
Karn 4	835	638	638	26	3,600	Water/Hydrogen	Yes	6	No	32F7/32H9	AGC Ramp Rate: 6 is avg. 9 Mw/min 70 thr. 500 Mw, 3 Mw/min 500 thr. 580 Mw
Ludington 1 (gen)	388	312	312	20	112.5	Air	Yes	6	No (2)	116	NDC is 312 MW but can operate at 340 MWg (338 MW net) at full pond.
Ludington 2 (gen)	388	312	312	20	112.5	Air	Yes	6	Yes	216	NDC is 312 MW but can operate at 340 MWg (338 MW net) at full pond.
Ludington 3 (gen)	388	312	312	20	112.5	Air	Yes	6	Yes	316	NDC is 312 MW but can operate at 340 MWg (338 MW net) at full pond.
Ludington 4 (gen)	388	312	312	20	112.5	Air	Yes	6	No (2)	416	NDC is 312 MW but can operate at 340 MWg (338 MW net) at full pond.
Ludington 5 (gen)	388	312	312	20	112.5	Air	Yes	6	Yes	516	NDC is 312 MW but can operate at 340 MWg (338 MW net) at full pond.
Ludington 6 (gen)	388	312	312	20	112.5	Air	Yes	6	No (2)	616	NDC is 312 MW but can operate at 340 MWg (338 MW net) at full pond.
Morrow A	20.7	14	17	13.8	3,600	Air	No	—	No	A16	Mothballed until February 2015.
Morrow B	20.7	14	17	13.8	3,600	Air	No	—	No	B16	Mothballed until February 2015.
Straits 1	25	16	21	13.8	3,600	Air	No	—	No	S16
Thetford 1	39.5	30	37	13.8	3,600	Air	No	—	No	116	Mothballed until October 2013.
Thetford 2	39.5	29	37	13.8	3,600	Air	No	—	No	216	Mothballed until October 2013.
Thetford 3	39.5	30	37	13.8	3,600	Air	No	—	Yes	316	Mothballed until May 2015.
Thetford 4	39.5	30	37	13.8	3,600	Air	No	—	Yes	416	Mothballed until May 2015.
Thetford 5	20.7	15	17	13.8	3,600	Air	No	—	No	516	Mothballed until October 2013.
Thetford 6	20.7	15	17	13.8	3,600	Air	No	—	No	616	Mothballed until October 2013.
Thetford 7	20.7	14	17	13.8	3,600	Air	No	—	No	716	Mothballed until October 2013.
Thetford 8	20.7	15	18	13.8	3,600	Air	No	—	Yes	816	Mothballed until May 2015.
Thetford 9	20.7	14	17	13.8	3,600	Air	No	—	Yes	916	Mothballed until May 2015.
Weadock 7	202	155	155	18	3,600	Hydrogen	Yes	1	No	799
Weadock 8	184	155	155	18	3,600	Hydrogen	Yes	1	No	899
Weadock A	21.9	13	17	13.8	3,600	Air	No	—	No	A16	Mothballed until October 2013.
Whiting 1	125	102	102	14.4	3,600	Hydrogen	Yes	1	No	199

Whiting 2	125	102	102	14.4	3,600	Hydrogen	Yes	1	No	299
Whiting 3	156.3	122	124	15.5	3,600	Hydrogen	Yes	1	No	399
Whiting A	21.9	13	17	13.8	3,600	Air	No	—	No	46A	Mothballed until October 2013.
Alcona Hydro 1	4.4	4	4	5	90	Air	NA	NA	No	116/166
Alcona Hydro 2	4.4	4	4	5	90	Air	NA	NA	No	216/166
Calkins Bridge Hydro 1	0.6	0.4	0.4	4.8	180	Air	NA	NA	No	116/166	Also known as Allegan Hydro
Calkins Bridge Hydro 2	1.1	0.9	0.9	4.8	120	Air	NA	NA	No	216/166	Also known as Allegan Hydro
Calkins Bridge Hydro 3	1.5	1.2	1.2	4.8	113	Air	NA	NA	No	316/166	Also known as Allegan Hydro
Cooke Hydro 1	3.3	1.5	1.5	2.5	180	Air	NA	NA	No	116/166
Cooke Hydro 2	3.3	3	3	2.5	180	Air	NA	NA	No	216/166
Cooke Hydro 3	3.3	3	3	2.5	180	Air	NA	NA	No	316/166
Croton Hydro 1	3.8	2.9	2.9	7.2	225	Air	NA	NA	No	116/246
Croton Hydro 2	3.8	2.9	2.9	7.2	225	Air	NA	NA	No	216/246
Croton Hydro 3	1.4	1.3	1.3	7.2	150	Air	NA	NA	No	316/246
Croton Hydro 4	1.6	1.3	1.3	7.2	150	Air	NA	NA	No	416/246
Five Channels 1	3.3	3.2	3.2	2.5	150	Air	NA	NA	No	116/166
Five Channels 2	3.3	3.2	3.2	2.5	150	Air	NA	NA	No	216/166
Foote Hydro 1	3.3	3.3	3.3	5	90	Air	NA	NA	No	116/366
Foote Hydro 2	3.3	3.3	3.3	5	90	Air	NA	NA	No	216/366
Foote Hydro 3	3.3	3.3	3.3	5	90	Air	NA	NA	No	316/366
Hodenpyl Hydro 1	8.9	9.2	9.2	7.5	120	Air	NA	NA	No	116/266
Hodenpyl Hydro 2	8.9	9.2	9.2	7.5	120	Air	NA	NA	No	216/266
Loud Hydro 1	2.2	2.2	2.2	2.5	120	Air	NA	NA	No	116/266
Loud Hydro 2	2.2	2.2	2.2	2.5	120	Air	NA	NA	No	216/266
Mio Hydro 1	2.7	2.2	2.2	2.5	80	Air	NA	NA	No	116/166
Mio Hydro 2	2.7	2.2	2.2	2.5	80	Air	NA	NA	No	216/166
Rogers Hydro 1	1.9	1.5	1.5	7.5	150	Air	NA	NA	No	116/166
Rogers Hydro 2	1.9	1.5	1.5	7.5	150	Air	NA	NA	No	216/166
Rogers Hydro 3	1.9	1.5	1.5	7.5	150	Air	NA	NA	No	316/166
Rogers Hydro 4	1.9	1.5	1.5	7.5	150	Air	NA	NA	No	416/166
Tippy Hydro 1	7.1	7	7	7.5	109	Air	NA	NA	No	116/266/126
Tippy Hydro 2	7.1	7	7	7.5	109	Air	NA	NA	No	216/266/126
Tippy Hydro 3	7.1	7	7	7.5	109	Air	NA	NA	No	316/266/126
Webber Hydro 1	3.3	2.3	2.3	7.2	164	Air	NA	NA	No	116/166
Webber Hydro 2	1.3	1	1	2.5	200	Air	NA	NA	No	216

Notes: (1) Rated MVA represents generator machine capability limits. Turbine or main transformer limits may be more restrictive. (2) Ludington units 1, 4 and 6 need to have one of the other units on line before they can be started.

EXHIBIT B - INTERCONNECTION ASSETS

General

The Parties agree that certain assets located at each of the electrical Substations at which Consumers’ Generation Resources are connected to the Transmission System are an integral part of the assets required by the Parties to provide services under their respective charters and that the physical partition would be impossible, impractical and wholly inconsistent with the purposes for which this Agreement is made. Said assets are deemed to be Jointly Owned Assets. In general, said assets include, but in some of the electrical Substations shall not be limited to, the following:

Foundations All foundations not identified as belonging to a specific piece of assets in the Plant Accounting Records.

Structures All steel support structures.

Station wiring All buswork, control cables, batteries, battery chargers and ground grids.

Fencing All chain-link fencing surrounding or used within the specific electrical Substation.

Control house Any building located within the Substation used to house relaying, controls or telemetry equipment beneficial to and used by both Parties.

Stone All stone used in the Substation yards, driveways and drains.

At each of the substations listed in this Exhibit B, an allocated percentage of the Jointly Owned Assets is determined for each Party hereto, in accordance with the provisions of this Agreement

For each of the electrical Substations at which Consumers’ Generation Resources are connected to the Transmission System, the specific assets allocated to and owned by Consumers are identified below as Consumers’ Interconnection Assets. In certain 345 kV Substations, specific breakers and associated assets that have been designated for operation by Consumers are also specifically identified as Transmission Owner’s Interconnection Assets.

Some of the electrical Substations containing Interconnection Assets also contain Distribution System assets owned by Consumers. Unless said Distribution System assets are directly involved in the connection of Consumers’ Generation Resources to the Transmission System, they are not described in the description of assets that follow.

The balance of the assets in each electrical Substation are allocated to and owned by the Transmission Owner and considered a part of the Transmission System.

Wiring Diagrams (WDs) will be updated continuously in each Party’s Drawing Management System (DMS) which is shared between the Parties and approved in writing by the Local Distribution Company to show changes in ownership. For current ownership (reflecting ownership changes since July 24, 2008), see the WDs in the DMS.

Exhibit B - Table 1

Jointly Owned Asset Ownership by Percent of Major Equipment

Addendum 3 - Final 008/16/12

Substations

Jointly Owned Assets

Percentage Split by Major Equipment Count

(Substations with 100% ownership by Major Equipment Count Not Included)

Substation Name	Distribution	Transmission	Generation Owned by Local Distribution Company	Third-Party Assets	Last Revision Date
Campbell 138 kV 1	—	64.28	35.24	0.48	8/16/2012
Cobb Plant	47.22	25.00	27.78		4/29/2002
Gaylord	44.44	44.44	11.12		1/1/2010
Karn Plant	—	63.64	36.36		1/1/2010
Morrow	63.33	30.00	6.67		8/16/2012
Thetford	—	92.00	8.00		4/29/2002
Weadock	35.14	24.32	40.54		1/1/2010
Whiting	28.57	28.57	42.86		8/16/2012

________________________

¹ At 120 kV and above, third-party related assets will be included as part of the Transmission assets for purposes of making this calculation. Also, the third party may share in the financial responsibility associated with O&M activities.

Changes, relative to previous revisions (addendums), are shown in bold type.

Major equipment is defined in Section 5.4 of the GIA.

Generator Connections located at Substations in the Transmission System

Campbell 1&2 Plant

The Campbell 1&2 Plant consists of three generating Units, known as Unit 1 (consisting of generators 1A and 1B), Unit 2 and Unit A. (The Campbell 3 Plant is located at the same site, but has separate interconnection facilities and is covered by a separate generator interconnection agreement.)

The Connection Point for Units 1, 2 and A are in the Campbell 138 kV Substation (see Wiring Diagram #93, Sheet 31 attached).

The Points of Receipt for all the Units in the Campbell 1&2 Plant are deemed to be the respective Connection Points.

Consumers’ Interconnection Assets

Consumers’ owns the following assets at the Campbell 138 kV Substation (Wiring Diagram #93, Sheet 31):

Transformer BankNo. A (located outside of substation; not included in JOA calc)

Circuit Breakers Nos. 199, 299, 799, 899*, 999 and 16A (16A is rated < 23kV and not considered major equipment per GIA definition).

Switches Nos. 99A, 195, 196, 295, 296, 709, 793, 795, 796, 809*, 893*, 895*, 896*, 909, 993, 995 and 996

Circuit Connections All wire, cable or buswork electrically connecting the switches identified above to the Circuit Breakers identified above and to the main or transfer buswork

Relay & Controls All relays and controls associated with the Circuit Breakers identified above

FoundationsAll foundations supporting the Circuit Breakers identified above

* Jointly Owned asset with Michigan Public Power Agency (4.8%) and Wolverine Power Supply Cooperative (1.8%)

Transmission Owner Interconnection Assets

Transmission Owner owns the following assets at the Campbell 138 kV Substation (Wiring Diagram #93, Sheet 31):

Transformer BankNo. 5

Circuit BreakersNos. 148, 188, 288, 388, 488, 500, 566 and 588

Switches Nos. 108, 144, 145, 146, 184, 185, 186, 208, 284, 285, 286, 308, 384, 385, 386, 408, 484, 485, 486, 505, 506, 508, 509, 545, 546, 564, 584, 585, 586, 1020 and 1121

Circuit Connections All wire, cable or bus work electrically connecting the switches identified above to the Circuit Breakers identified above and to the main or transfer bus work

Relay and Controls All relays and controls associated with the Circuit Breakers identified above

Foundations All foundations supporting the Circuit Breakers identified above

Jointly Owned Assets - Percentage Split by Major Equipment Count

Campbell 138 kV Substation - See Exhibit B - Table 1

CEII MATERIAL

Cobb Generating Plant Complex

The Cobb Generating Plant Complex consists of five generating Units, known as Units 1 through 5, respectively.

The Connection Points for Units 1 through 5 are in the BC Cobb Plant Substation (see Wiring Diagram #240, Sheet 31 attached).

The Points of Receipt for all the Units in the Cobb Generating Plant Complex are deemed to be the respective Connection Points.

Consumers’ Interconnection Assets

Consumers owns the following assets at the BC Cobb Plant Substation (Wiring Diagram #240, Sheet 31):

Transformer BanksNos. 1, 2, 3, 4, 5, 7 and 8

Capacitor Banks Nos. 1 and 2

Circuit Breakers Nos. 100, 188, 199, 288, 299, 399, 499, 599, 766, 799, 866, 899, 1177, 1188, 1288, 1388, 1488 and 1688

Switches Nos. 102, 104, 152, 156, 184, 185, 186, 193, 195, 196, 200, 252, 256, 284, 285, 286, 293, 295, 296, 393, 395, 396, 493, 495, 496, 593, 595, and 596, 709, 762, 764, 765, 793, 795, 796, 809, 862, 864, 865, 893, 895, 896, 1171, 1173, 1175, 1182, 1184, 1185, 1282, 1284, 1285, 1323, 1382, 1384, 1385, 1482, 1484, 1485, 1588, 1682, 1684, 1685, 1788, 1888, 2333, 7732-1, 7736-1, 8826-2, 8832-2 and 8836-2

Circuit Connections All wire, cable or buswork electrically connecting the switches identified above to the Circuit Breakers identified above and to the main buswork.

Relay & Controls All relays and controls associated with the Circuit Breakers identified above

Foundations All foundations supporting the Transformers and Circuit Breakers identified above

Auxiliary Power All 2400 Volt station power assets shown in the attached Wiring Diagram #240

Transmission Owner Interconnection Assets

Transmission Owner owns the following assets at the BC Cobb Plant Substation (Wiring Diagram #240, Sheet 31):

Circuit Breakers Nos. 148, 377, 488, 500, 588, 688, 788, 888 and 988

Switches Nos. 144, 145, 146, 307, 373, 375, 376, 408, 484, 485, 486, 505, 506, 508, 584, 585, 586, 608, 684, 685, 686, 708, 784, 785, 786, 808, 884, 885, 886, 908, 984, 985, 986, 1020, 1121, 2030 and 2131

Circuit Connections All wire, cable or buswork electrically connecting the switches identified above to the Circuit Breakers identified above and to the main buswork.

Relay & Controls All relays and controls associated with the Circuit Breakers identified above

Foundations All foundations supporting the Circuit Breakers identified above

Jointly Owned Assets - Percentage Split by Major Equipment Count

Cobb Plant Substation -See Exhibit B - Table 1

CEII MATERIAL

Gaylord Generating Plant Complex

The Gaylord Generating Plant Complex consists of five combustion turbine generating Units, known as Units 1 through 5, respectively.

The Connection Points for Units 1 through 5 are in the Gaylord Generating Substation (see Wiring Diagram #495, Sheet 31 attached).

The Points of Receipt for all the Units in the Gaylord Generating Plant Complex are deemed to be the respective Connection Points.

Consumers’ Interconnection Assets

Consumers owns the following assets at the Gaylord Generating Substation (Wiring Diagram #495, Sheet 31):

Transformer BanksNos. 1, 2* and 3* (*located outside of substation; not included in JOA calc)

Circuit Breakers Nos. A16*, 116*, 146, 166, 199, 216*, 316*, 416* and 1288 (*located outside of substation; not included in JOA calc)

Switches Nos. 3,142, 144, 145, 162, 164, 165, 191, 193, 195, 299, 399, 1282 and 1284

Circuit Connections All wire, cable or buswork electrically connecting the switches identified above to the Circuit Breakers identified above

Relay & Controls All relays and controls associated with the Circuit Breakers identified above

Foundations All foundations supporting the Transformers and Circuit Breakers identified above

Auxiliary Power All station power assets shown in the attached Wiring Diagram #495, Sheet 31

Transmission Owner Interconnection Assets

Transmission Owner owns the following assets at the Gaylord Generating Substation (Wiring Diagram #495, Sheet 31):

Capacitor Bank No. 3

Circuit Breakers Nos. 356, 377 and 477

Switches Nos. 352, 371, 373, 375. 382, 384, 385, 471, 473, 475, 671, 673 and 675

Circuit Connections All wire, cable or buswork electrically connecting the switches identified above to the Circuit Breakers identified above

Relay & Controls All relays and controls associated with the Circuit Breakers identified above

Foundations All foundations supporting the Circuit Breakers identified above

Jointly Owned Assets - Percentage Split by Major Equipment Count

Gaylord Generating Substation - See Exhibit B - Table 1

CEII MATERIAL

Karn Generating Plant Complex

The Karn Generating Plant Complex consists of four generating Units, known as Units 1 (consisting of generators 1A and 1B), Unit 2 (consisting of generators 2A and 2B, Unit 3 and Unit 4.

The Connection Point for Units 1 and 2 are in the DE Karn Plant 138 kV Substation (see Wiring Diagram #695, Sheet 31 attached). The Connection Point for Units 3 and 4 are in the Hampton 345 kV Substation (see Wiring Diagram #1327, Sheet 31 attached).

The Points of Receipt for all the Units in the DE Karn Generating Plant Complex are deemed to be the respective Connection Points.

Consumers’ Interconnection Assets

Consumers owns the following assets at the DE Karn 138 kV Substation (Wiring Diagram #695, Sheet 31):

Transformer Banks Nos. 1 and 2 (located outside the substation; not included in JOA calc)

Circuit BreakersNos. 199, 299, 799 and 899

Switches Nos. 136A, 136B, 195, 196, 236A, 236B, 295, 296, 793, 795, 796, 893, 895, and 896

Circuit Connections All wire, cable or buswork electrically connecting the switches identified above to the Circuit Breakers identified above and to the main or transfer buswork

Relay & Controls All relays and controls associated with the Circuit Breakers identified above

FoundationsAll foundations supporting the Circuit Breakers identified above

Auxiliary Power All 480 Volt and 4160 Volt station power assets shown in the attached Wiring Diagram #695, Sheet 31

Transmission Owner’s Interconnection Assets

Transmission Owner owns the following assets at the DE Karn 138 kV Substation (Wiring Diagram #695, Sheet 31):

Circuit BreakersNos. 148, 188, 388, 488, 500, 588 and 988

Switches Nos. 108, 144, 145, 146, 184, 185, 186, 308, 384, 385, 386, 408, 484, 485, 486, 505, 506, 508, 584, 585, 586, 709, 809, 908, 984, 985, 986, 2030 and 2131

Circuit Connections All wire, cable or buswork electrically connecting the switches identified above

to the Circuit Breakers identified above and to adjacent buswork

Relay & Controls All relays and controls associated with the Circuit Breakers identified above

FoundationsAll foundations supporting the Circuit Breakers identified above

Jointly Owned Assets - Percentage Split by Major Equipment Count

Karn Plant Substation - See Exhibit B - Table 1

CEII MATERIAL

Ludington Pumped Storage Generating Plant Complex

Note: The Detroit Edison Company has a overall 49% ownership interest in the Ludington Generating Plant and certain other related facilities and property.

The Ludington Pumped Storage Generating Plant Complex consists of six motor-generator Units, known as Units 1 through 6, respectively.

The Connection Points for Units 1 through 6 are in the Ludington Substation (see Wiring Diagram #1405, Sheet 31 attached).

The Points of Receipt for all the Units in the Ludington Pumped Storage Generating Plant Complex are deemed to be the respective Connection Points.

Generator Interconnection Assets

Consumers Energy and Detroit Edison, as noted above, share ownership of the following assets at the Ludington Site (Wiring Diagram #1405, Sheet 31):

Transformer Banks Nos. 1, 2, and 3 (located outside the substation; not included in JOA calc)

ReactorsNos. 1 and 2 (located outside the substation; not included in JOA calc)

Circuit Breakers Nos. 115, 116, 216, 316, 416 516, 615 and 616 (all phase-reversing 3-pole breakers associated with the motor-generators) and Nos. 1116 and 6116 (breakers associated with Pony Motors Nos. 1 and 2) (located outside the substation; not included in JOA calc)

Switches Nos. 105, 215, 315, 415, 515, 1099, 1112 and 6112

Removable Links Nos. 111, 112, 113, 212, 213, 312, 313, 412, 413, 512, 513, 612 and 613

Circuit Connections All 345 kV conductors connecting the 20/345 kV Transformer Banks to the 345 kV buswork in the Ludington Substation

All wire, cable or buswork electrically connecting the switches identified above to the Circuit Breakers identified above and to the 20 kV main and starting buswork

Relay & Controls All relays and controls associated with the Circuit Breakers identified above

Foundations All foundations supporting the Transformers and Circuit Breakers identified above

Auxiliary Power All 480 Volt and 4160 Volt station power assets shown in the attached Wiring Diagram #1405, Sheet 31

Transmission Owner’s Interconnection Assets

Transmission Owner and Third Party share ownership of the following assets at the Ludington Substation (Wiring Diagram #1405, Sheet 31):

ReactorsNos. 21 and 23

Circuit Breakers Nos. 21F7, 21R8, 22F7, 22H9, 22R8, 23F7, 23R8, 24F7, 24H9, 24R8, 25F7, 25H9*, 25R8*, 26F7, 26R8, 2156 and 2356

Switches Nos. 21F1, 21F3, 21R2, 21R4, 2156, 22F1, 22F3, 22H5, 22H6, 22R2, 22R4, 23F1, 23F3, 23R2, 23R4, 2356, 24F1, 24F3, 24H5, 24H6, 24R2, 24R4, 25F1, 25F3, 25H5*, 25H6*, 25R2*, 25R4*, 26F1, 26H6, 26R2, 26R4, 2152 and 2352

Circuit Connections All 345 kV conductors connecting the 20/345 kV Transformer Banks to the 345 kV buswork in the Ludington Substation

All wire, cable or buswork electrically connecting the switches identified above to the Circuit Breakers identified above and to the 20 kV main and starting buswork

Relay & Controls All relays and controls associated with the Circuit Breakers identified above

FoundationsAll foundations supporting the Circuit Breakers identified above

*100% owned by Transmission Owner

Jointly Owned Assets - Percentage Split by Major Equipment Count

Ludington Substation - Consumers (generation) = 0.00%; Consumers (distribution) = 0.00%;

Transmission Owner = 56.16%; Third Parties = 43.84%

CEII MATERIAL

Morrow Generating Plant Complex

The Morrow Generating Plant Complex consists of two combustion turbine generating Units, known as Units A and B.

The Connection Points for both Units A and B are in the Morrow Substation (see Wiring Diagram #190, Sheet 31, attached).

The Points of Receipt for the Units in the Morrow Generating Plant Complex are deemed to be the Connection Points.

Consumers’ Interconnection Assets

Consumers’ owns the following assets at the Morrow Substation (Wiring Diagram #190, Sheet 31):

Transformer Banks No. 1, 2, 4 and 5

Circuit Breakers Nos. 100, 156, 166, 199, 256, 266, 299, 566, 499, 16A,16B, 599, 1077, 1188, 1388, 1488, 1588, 1688 and 1788

Switches Nos. 102, 104, 109, 162, 164, 165, 191, 193, 195, 196, 209, 252, 262, 264, 265, 291, 293, 295, 296, 300, 495, 496, 509, 562, 564, 565, 591, 593, 595, 596, 1071, 1073, 1075, 1182, 1184, 1185, 1323, 1382, 1384, 1385, 1482, 1484, 1485, 1582, 1584, 1585, 1682, 1684, 1685, 1782, 1784, 1785 and 2333

CapacitorsNos. 1 and 2

Circuit Connections All wire, cable or buswork electrically connecting the Transformers, Circuit Breakers and Switches identified above

Relay & Controls All relays and controls associated with the Circuit Breakers identified above

Foundations All foundations supporting the Transformers and Circuit Breakers identified above

Auxiliary Power All 480 Volt station power assets shown in the attached Wiring Diagram #190, Sheet 31

Transmission Owner Interconnection Assets

Transmission Owner owns the following assets at the Morrow Substation (Wiring Diagram #190, Sheet 31):

Circuit BreakersNos. 177, 288, 377, 388, 500, 588, 677, 888 and 988

Switches Nos. 107, 171, 173, 175, 176, 208, 282, 284, 285, 286, 307, 308, 371, 373, 375, 376, 382, 384, 385, 386, 501, 502, 503, 504, 505, 506, 508, 582, 584, 585, 586, 607, 671, 673, 675, 676, 882, 884, 885, 886, 908, 982, 984, 985 and 986

Circuit Connections All wire, cable or buswork electrically connecting the Circuit Breakers and Switches identified above

Relay and Controls All relays and controls associated with the Circuit Breakers identified above

Foundations All foundations supporting the Circuit Breakers identified above

Third Party Owned Assets

None

Jointly Owned Assets - Percentage Split by Major Equipment Count

Morrow Substation - See Exhibit B - Table 1

CEII MATERIAL

Thetford Generating Plant Complex

The Thetford Generating Plant Complex consists of nine combustion turbine generating Units, known as Units 1 through 9, respectively.

The Connection Points for Units 1 through 9 are in the Thetford Substation (see Wiring Diagram #1000, Sheet 31 attached).

The Points of Receipt for all the Thetford Units are deemed to be the respective Connection Points.

Consumers’ Interconnection Assets

Consumers owns the following assets at the Thetford Substation (Wiring Diagram #1000, Sheet 31):

Transformer Banks Nos. 5, 6-1, 6-2 and 7

Circuit BreakersNos. 13B7, 13W8, 116, 216, 316, 416, 516, 616, 716, 816 and 916

SwitchesNos. 13B1, 13B3, 13M5, 13W2, 13W4, 591, 691-1, 691-2 and 791

Circuit Connections All wire, cable or buswork electrically connecting the Transformer Banks, Circuit Breakers and Switches identified above

Relay & Controls All relays and controls associated with the Circuit Breakers identified above

Foundations All foundations supporting the Transformers and Circuit Breakers identified above

Transmission Owner Interconnection Assets

Transmission Owner owns the following assets at the Thetford Substation (Wiring Diagram #1000, Sheet #31):

Transformer Banks Nos. 3 and 4

Circuit Breakers Nos. 6B7, 6M9, 6W8, 7B7, 7M9, 7W8, 9B7, 9M9, 9W8, 11B7, 11M9, 11W8, 27F7, 27H9, 27R8, 31F7, 31H9, 31R8, 33F7, 33H9 and 33R8

Switches Nos. 6B1, 6B3, 6M5, 6M6, 6W2, 6W4, 7B1, 7B3, 7M5, 7M6, 7W2, 7W4, 9B1, 9B3, 9M5, 9M6, 9W2, 9W4, 11B1, 11B3, 11M5, 11M6, 11W2, 399, 499, 11W4, 27F1, 27F3, 27H5, 27H6, 27R2, 27R4, 31F1, 31F3, 31H5, 31H6, 31R2, 31R4, 33F1, 33F3, 33H5, 33H6, 33R2, 33R4 and 35R2

Circuit Connections All wire, cable or buswork electrically connecting the Transformer Banks, Circuit Breakers and Switches identified above

Relay and Controls All relays and controls associated with the Circuit Breakers identified above

Foundations All foundations supporting the Transformers and Circuit Breakers identified above

Jointly Owned Assets - Percentage Split by Major Equipment Count

Thetford Substation - See Exhibit B - Table 1

CEII MATERIAL

Weadock Generating Plant Complex

The Weadock Generating Plant Complex consists of three generating Units, known as Units 7, 8 and A.

The Connection Points for Units 7, 8 and A1 are in the John C Weadock Substation (see Wiring Diagram #195, Sheet 31 attached). These Units are currently in service. In addition, there are six other units, known as Units 1 through 6, which have been retired from service, but are still in place. Those assets are also described below, should the Units be restored to service in the future.

The Points of Receipt for all the Units currently in service at the Weadock Generating Plant Complex are deemed to be the respective Connection Points.

Consumers’ Interconnection Assets (for Units In Service)

Consumers owns the following assets at the John C Weadock Substation (Wiring Diagram #195, Sheets 2 and 31):

Transformer Banks Nos. 1, 2, 7, 8, 9 and 10

Circuit Breakers Nos. 66A, 100, 136, 166, 199, 236, 266, 299, 300, 736C, 799, 899, 966, 999, 1066, 1088, 1099, 1188, 1288 and 1388

Switches Nos. 62A, 64A, 102, 104, 105, 106, 132, 134, 135, 152, 156, 162, 164, 165, 195, 196, 200, 232, 234, 235, 252, 256, 262, 264, 265, 295, 296, 302, 304, 306, 400, 732C, 734C, 735C, 736A, 736B, 795, 796, 836A, 836B, 895, 896, 962, 964, 965, 991, 993, 995, 996, 1062, 1064, 1065, 1082, 1084, 1085, 1091, 1093, 1095, 1096, 1182, 1184, 1185, 1282, 1284, 1285, 1382, 1384 and 1385

Capacitors1 and 2

Circuit Connections All wire, cable or buswork electrically connecting the Switches identified above to the Circuit Breakers identified above and to the main buswork.

Relay & Controls All relays and controls associated with the Circuit Breakers identified above

Foundations All foundations supporting the Transformer Banks and Circuit Breakers identified above

Auxiliary Power All 480 Volt and 4160 Volt station power assets shown in the attached Wiring Diagram #195, Sheet 31

Consumers’ Interconnection Assets (for Units Retired in Place)

Consumers owns the following assets at the John C Weadock Substation (Wiring Diagram #195, Sheet 31):

Transformer BanksNos. 5 and 6

Circuit BreakersNos. 99A, 116, 216, 316, 336, 416 and 436

Switches Nos. 93A, 112, 114, 212, 214, 312, 314, 332, 412, 414, 432, 516, 536 and 616

Circuit Connections All wire, cable or buswork electrically connecting the Switches identified above to the Circuit Breakers identified above and to the main buswork.

Relay & Controls All relays and controls associated with the Circuit Breakers identified above

Foundations All foundations supporting the Transformer Banks and Circuit Breakers identified above

Transmission Owner Interconnection Assets

Transmission Owner owns the following assets at the John C Weadock Substation (Wiring Diagram #195, Sheet 31):

Circuit BreakersNos. 148, 188, 288, 388, 488, 500, 588, 688 and 788

Switches Nos. 108, 142, 144, 145, 146, 182, 184, 185, 186, 208, 282, 284, 285, 286, 308, 382, 284, 385, 386, 408, 482, 484, 485, 486, 505, 506, 508, 582, 584, 585, 586, 608, 682, 684, 685, 686, 708, 782, 784, 785, 786, 900, 1020,1121, 2030, 2131, 3040, 3141, 4050 and 4151

Circuit Connections All wire, cable or buswork electrically connecting the Switches identified above to the Circuit Breakers identified above and to the main buswork

Relay & Controls All relays and controls associated with the Circuit Breakers identified above

Foundations All foundations supporting the Circuit Breakers identified above

Jointly Owned Assets - Percentage Split by Major Equipment Count

John C Weadock Substation - See Exhibit B - Table 1

CEII MATERIAL

Whiting Generating Plant Complex

The Whiting Generating Plant Complex consists of four generating Units, known as Units 1, 2, 3 and A.

The Connection Points for Units 1, 2, 3 and A are in the Whiting Substation (see Wiring Diagram #400, Sheet 31attached). Units 1, 2 and 3 are connected to the 138 kV buswork and Unit A is connected to the 46 kV buswork

The Points of Receipt for all the Units in the Whiting Generating Plant Complex are deemed to be the respective Connection Points.

Consumers’ Interconnection Assets

Consumers owns the following assets at the Whiting Substation (Wiring Diagram #400, Sheet 31):

Transformer Banks Nos. 1, 2, 3, 5, 7 and A (TB # A located outside of substation; not included in JOA calc)

Circuit Breakers Nos. 16A (located outside switchyard; not included in JOA calc), 46A, 199, 299, 399, 599, 766, 799, 1188 and 1288

Switches Nos. 42A, 44A, 45A, 99A, 105, 156, 191, 193, 195, 196, 291, 293, 295, 296, 391, 393, 395, 396, 591, 593, 79T1, 762, 764, 765, 795, 796, 1182, 1184, 1185, 1282, 1284, 1285

Capacitor Bank No 1

Circuit Connections All wire, cable or buswork electrically connecting the Transformer Banks, Circuit Breakers and Switches identified above to each other, as appropriate, to the main buswork and to the Auxiliary Power assets

Relay & Controls All relays and controls associated with the Circuit Breakers identified above

Foundations All foundations supporting the Transformer Banks and Circuit Breakers identified above

Auxiliary Power All 480 Volt and 2400 Volt station power assets shown in the attached Wiring Diagram #400, Sheet 31

Transmission Owner Interconnection Assets

Transmission Owner owns the following assets at the Whiting Substation (Wiring Diagram #400, Sheet 31):

Transformer Bank No. 8

Circuit BreakersNos. 500, 688, 788,899 and 988

Switches Nos. 501, 502, 503, 504, 505, 506, 608, 682, 684, 685, 686, 785, 786, 866, 895, 896, 908, 982, 984, 985 and 986

Circuit Connections All wire, cable or buswork electrically connecting the Transformer Banks, Circuit Breakers and Switches identified above to each other, as appropriate, to the main buswork

Relay & Controls All relays and controls associated with the Circuit Breakers identified above

Foundations All foundations supporting the Transformer Bank and Circuit Breakers identified above

Jointly Owned Assets - Percentage Split by Major Equipment Count

Whiting Substation - See Exhibit B - Table 1

CEII MATERIAL

EXHIBIT C

Generator Connections located in Consumers’ Distribution System

The following Units are connected indirectly to the Transmission System and do not have specific connection data listed herein.

Alcona Hydro Generating Plant, Units 1 and 2

Calkins Bridge “Allegan” Hydro Generating Plant, Units 1, 2 and 3

Cooke Hydro Generating Plant, Units 1. 2 and 3

Croton Hydro Generating Plant, Units 1, 2, 3 and 4

Five Channels Generating Plant, Units 1 and 2

Foote Hydro Generating Plant, Units 1, 2 and 3

Hodenpyl Hydro Generating Plant, Units 1 and 2

Loud Hydro Generating Plant, Units 1 and 2

Mio Hydro Generating Plant, Units 1 and 2

Rogers Hydro Generating Plant, Units 1, 2, 3 and 4

Straits Combustion Turbine Generating Unit 1

Tippy Hydro Generating Plant, Units 1, 2 and 3

Webber Hydro Generating Plant, Units 1 and 2

Consumers Energy Generator Connections Covered under Other Interconnection Agreements

The following Units are covered under their own LGIAs and do not have specific connection data listed herein.

Campbell Generating Plant, Unit 3.

Hardy Hydro Generating Plant, Units 1, 2 and 3.

Zeeland Power Plant

EX-10.121

EXHIBIT 10.121

FERC rendition of the electronically filed tariff records in Docket No. ER13-01907-000

Filing Data:

CID: C001344

Filing Title: 2013-07-08 SA 1756 METC-Consumers (G479B)

Company Filing Identifier: 859

Type of Filing Code: 10

Associated Filing Identifier:

Tariff Title: Midwest ISO Agreements

Tariff ID: 13

Payment Confirmation:

Suspension Motion: N

Tariff Record Data:

Record Content Description, Tariff Record Title, Record Version Number, Option Code:

SA 1756, METC-Consumers, 3.0.0, A

Record Narative Name:

Tariff Record ID: 5077

Tariff Record Collation Value: 1879139756 Tariff Record Parent Identifier: 4593

Proposed Date: 2013-07-04

Priority Order: 500

Record Change Type: CHANGE

Record Content Type: 1

Associated Filing Identifier:

SA 1756 METC-Consumers Version: 3.0.0 Effective: 7/4/2013

Seventh Revised Service Agreement No. 1756

Public Version

AMENDED AND RESTATED

GENERATOR INTERCONNECTION AGREEMENT

entered into by the

Midcontinent Independent System Operator, Inc.

Michigan Electric Transmission Company

and

Consumers Energy Company

Amended and Restated

GENERATOR INTERCONNECTION AGREEMENT

by and among

Michigan Electric Transmission Company, LLC

and

Consumers Energy Company

and the

Midcontinent Independent System Operator, Inc.

Amended and Restated

GENERATOR INTERCONNECTION AGREEMENT

THIS Amended AND RESTATED GENERATOR INTERCONNECTION AGREEMENT(the "Agreement") is made and entered into as of _June 13____-, 2013 by and among Michigan Electric Transmission Company, LLC, a limited liability company with offices at 27175 Energy Way Novi, Michigan (herein referred to as “METC” or "Transmission Owner”), Consumers Energy Company, a Michigan corporation with offices at One Energy Plaza, Jackson, Michigan (herein referred to as “Consumers” or “Interconnection Customer”), and the Midcontinent Independent System Operator, Inc., formerly known as Midwest Independent Transmission System Operator, Inc., a non-profit, non-stock corporation organized and existing under the laws of the State of Delaware (herein referred to as “MISO” or “Transmission Provider”). Transmission Provider, Consumers and Transmission Owner each may be referred to individually as a "Party," or collectively as the "Parties." This Agreement amends, restates and replaces the September 18, 2012 Amendment and Restatement of the Generator Interconnection Agreement between the Transmission Owner, Transmission Provider and Consumers, effective on the Effective Date provided for below in Section 2.1.

WITNESSETH:

WHEREAS, Consumers owns and operates several electric generating assets (herein referred to as a Unit when discussing one of them, or as Generation Resources when referring to all of them) as described in Article 1. The Unit names and generating capability ratings of the Generation Resources are set forth in Exhibit A to this Agreement. Each Unit in the list is currently in commercial operation; and

WHEREAS, Transmission Provider has functional control of the operation of the Transmission System, as defined in Article 1 of this Agreement, and is responsible for providing transmission and interconnection service on the transmission facilities under its functional control; and

WHEREAS, Transmission Owner owns or operates the Transmission System, whose operations are subject to the functional control of the Transmission Provider, to which the Consumers’ Units are interconnected, as set forth in this Agreement; and

WHEREAS, it is necessary for Consumers’ Units to remain interconnected with the Transmission System (as defined in Article 1), in order for said Units to continue to operate; and

WHEREAS, the revised and restated Agreement is not intended to affect METC’s and Consumer’s obligations to each other with regard to the following agreements:

WHEREAS, Consumers and Transmission Owner have entered into an Operating Agreement, dated as of April 1, 2001, as amended and restated, (herein referred to as the “Operating Agreement”) that defines the operating responsibilities of the Transmission Owner with respect to the Transmission System and the obligations, rights and responsibilities of Consumers to provide ancillary services and to operate its Generation Resources in a manner that will not unduly interfere with the provision of Transmission Services by the Transmission Owner; and

WHEREAS, Consumers, Transmission Owner and Transmission Provider have entered into a Purchase and Sale Agreement for Ancillary Services, dated as of April 1, 2001, as amended and restated, that sets forth the terms and conditions under which Consumers shall use its Generation Resources to provide ancillary services to the Transmission Owner and Transmission Provider;

and

WHEREAS, the Parties are willing to maintain the interconnection of Consumers’ Generation Resources with the Transmission System under the terms and conditions contained herein.

NOW, THEREFORE, in consideration of and subject to the mutual covenants contained herein, the Parties hereto agree as follows:

ARTICLE 1

DEFINITIONS

1.1 Whenever used in this Agreement, appendices, and attachments hereto, the following terms shall have the following meanings:

“Black Start Capability” shall mean a generating Unit that is capable of starting without an outside electrical supply. Said Units are specified in Exhibit A.

“Black Start Plan” shall mean a plan utilizing Black Start Capability designed and implemented by the Transmission Provider or Transmission Owner in conjunction with its interconnected generation and distribution customers, Distribution System Control, other electric systems, its Security Coordinator and ECAR, to energize portions of the Transmission System which are de-energized as a result of a widespread system disturbance.

“Black Start Service” shall mean the provision of service needed to energize a defined portion of the Transmission Owner’s Transmission System, including the start up of the Generation Resources and/or other generators, in accordance with the Transmission Provider’s or Transmission Owner’s Black Start Plan when local power from the Transmission System is unavailable or insufficient.

"Commission" shall mean the Federal Energy Regulatory Commission, or any successor agency.

“Connection Point” shall be the point where Consumers’ Interconnection Assets connect to Transmission Owner’s Interconnection Assets, as described in Exhibit B of this Agreement.

“Consumers’ Incremental Cost” shall mean Consumers’ actual hourly replacement cost of energy on Consumers’ Generation Resources, whether that energy is (a) produced by generation owned by or under contract to Consumers or (b) purchased from a third party.

“Consumers’ Interconnection Assets” shall mean the assets identified as belonging to Consumers in Exhibit B of this Agreement and all other assets that are necessary or desirable to interconnect a Unit to the Transmission System reliably and safely, including all connection, switching, transmission, distribution, safety, and communication assets, protective assets, Telemetry and Monitoring Assets that Consumers owns or operates and maintains.

"Consumers’ System" shall mean the assets owned, controlled and operated by Consumers that are used to provide service to its customers.

“ECAR” stands for the East Central Area Reliability council or a successor group.

"Emergency" shall mean any system condition that requires automatic or immediate manual action to prevent or limit the loss of transmission assets or generation supply that could adversely affect the reliability of Transmission System or Consumers’ System or the systems to which either Party is directly or indirectly connected.

“Generation Resources” shall mean the assets used for the production of electric energy, which are owned and operated by Consumers and directly or indirectly connected to the Transmission System pursuant to this Agreement.

"Good Utility Practice" shall mean any of the practices, methods and acts engaged in or approved by a significant proportion of the electric utility industry during the relevant time period, or any of the practices, methods and acts which, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety and expedition. Good Utility Practice is not intended to be limited to the optimum practice, method or act to the exclusion of all others, but rather to be acceptable practices, methods or acts generally accepted in the region.

“Governmental Authority” shall mean any federal, state, local or municipal governmental body; any governmental, regulatory or administrative agency, commission, body or other authority exercising or entitled to exercise any administrative, executive, judicial, legislative, policy, regulatory or taxing authority or power; or any court or governmental tribunal.

"Hazardous Substances" shall mean any chemicals, materials or substances defined as or included in the definition of "hazardous substances", "hazardous wastes", "hazardous materials", "hazardous constituents", "restricted hazardous materials", "extremely hazardous substances", "toxic substances", "contaminants", "pollutants", "toxic pollutants" or words of similar meaning and regulatory effect under any applicable Environmental Law, or any other chemical, material or substance, exposure to which is prohibited, limited or regulated by any applicable Environmental Law. For purposes of this Agreement, the term "Environmental Law" shall mean federal, state, and local laws, regulations, rules, ordinances, codes, decrees, judgments, directives, or judicial or administrative orders relating to pollution or protection of the environment, natural resources or human health and safety.

“IEEE” is an acronym, which stands for the Institute of Electrical and Electronic Engineers.

“Interconnection Assets” shall mean, collectively, Transmission Owner’s Interconnection Assets and Consumers’ Interconnection Assets, or the specific Interconnection Assets of either the Transmission Owner or Consumers, as the case may be.

“Jointly Owned Assets” shall mean those assets in which Consumers and Transmission Owner have undivided ownership interests. Due to the nature of substation designs, many of the supporting substation assets (e.g., station batteries, fencing, control houses, ground grid, yard stone, steel structures and some protective relay assets) cannot be separated by ownership and the Parties share in the ownership of such assets. The respective ownership of such assets by substation is shown in Exhibit B hereto.

“Metering Assets” shall mean the assets required to provide acceptably accurate metering of the interconnection power and energy output from the Unit and the standby power and energy

usage of the Unit. Said Metering Assets typically includes but is not limited to, metering accuracy potential and current transformers, transducers, primary connections, secondary connections, secondary potential and current circuits and conduit, telephone lines and access to said Metering Assets, if necessary. The transducers used shall be capable of providing Megawatthour and Megavarhour data.

“MISO” shall mean the Midcontinent Independent System Operator, Inc., or its successor.

“MISO Tariff” shall mean the Open Access Transmission, Energy and Operating Reserve Markets Tariff on file with the Commission as it may be amended or superseded from time to time.

“Monitoring Assets” shall mean the assets required to determine (a) the sequence of events for the operation of protective assets during an electrical fault, (b) the location and characteristics of an electrical fault and (c) the quality of power provided at the Point of Receipt.

"NERC" is an acronym that stands for the North American Electric Reliability Council, including any successor thereto or any regional reliability council thereof. This reliability council oversees the development and publication of operating policies, engineering planning principles and guides and support information to provide guidance to the regional reliability councils and to promote electric system reliability.

“Point of Receipt” shall be the point at which capacity and energy is provided by Consumers, as described in Exhibit B of this Agreement.

“Reactive Design Limitations” shall mean the reactive power capability designed into the Unit, which were consistent with reactive power capability specifications in place when the Unit was constructed.

"Secondary Systems" shall mean control or power circuits that operate below 600 volts, AC or DC, including, but not limited to, any hardware, control or protective devices, cables, conductors, electric conduits and raceways, secondary assets panels, transducers, batteries, chargers, and voltage and current transformers.

"Switching and Tagging Rules" shall mean the written documents describing the switching and tagging procedures of Transmission Owner and Consumers, as they may be amended.

“System Operator” is a generic term used to describe the individuals responsible for the integrity or the operational control of the Transmission System and any successor thereto.

"System Protection Assets" shall mean the assets required to protect (a) the Transmission System, the systems of others connected to the Transmission System, and Transmission Owner’s customers from faults occurring at the Unit, and (b) the Unit from faults occurring on the Transmission System or on the systems of others to which the Transmission System is directly or indirectly connected.

“Telemetry Equipment” shall mean the assets, identified by Transmission Owner, that are required to provide the necessary, real-time telemetry of Unit operations and status, as required by Transmission Owner, for remote monitoring and control purposes. This typically includes but is not limited to, remote terminal units, distributed terminal units, telemetry signal inputs, fiber optic communication connections, transducers, pulse multipliers, isolation amplifiers, analog inputs, digital inputs, metering pulsed accumulator inputs, power supply, dedicated telephone data line to

remote terminal units, telephone modem, telephone switching, interface terminal strips for landing signal inputs/outputs. Telemetry Equipment may be located at Consumers’ Unit and or at Transmission Owner’s assets.

“Transmission Owner” shall mean Michigan Electric Transmission Company, LLC or its successor.

“Transmission Owner’s Interconnection Assets” shall mean the assets identified as belonging to Transmission Owner in Exhibit B of this Agreement and all other assets that are necessary or desirable to interconnect the Generation Resources to the Transmission System reliably and safely, including all connection, switching, transmission, distribution, safety, and communication assets, protective assets, Metering, Telemetry and Monitoring Assets and all improvements, additions or extensions to the Transmission System owned or operated and maintained by the Transmission Owner and that are attributable to or necessitated by the Generation Resources.

“Transmission Provider” shall mean MISO.

"Transmission System" shall mean the facilities owned by the Transmission Owner and controlled or operated by the Transmission Provider or Transmission Owner that are used to provide transmission service under the MISO Tariff.

“Transmission Service” shall include both Point-To-Point Transmission Service and Network Integration Transmission Service provided under the MISO Tariff.

"Unit" shall mean each of Consumers’ electric generating assets, or group of generating assets having common Interconnection Assets, covered by this Agreement and identified generally in the first "Whereas" clause and Exhibit A of this Agreement and more specifically identified in the "as built" drawings provided to Transmission Owner in accordance with Section 4.3 of this Agreement, together with the other property, assets, and assets owned and/or controlled by Consumers on the Consumers' side of the Connection Point.

ARTICLE 2

TERM OF AGREEMENT

2.1Effective Date

This Agreement shall become effective on the date designated by the Commission in its order accepting this Agreement for filing (the “Effective Date”).

2.2Term

This Agreement shall become effective as provided in Section 2.1 above and, unless terminated as provided below, shall continue in full force and effect until a mutually agreed termination date, but no later than the date on which all of the Generation Resources cease commercial operation.

2.3Termination

In the event that Transmission Owner joins a Regional Transmission Organization (“RTO”) which requires use of its own FERC-approved interconnection and operating agreement, this Agreement shall terminate on the effective date of such new interconnection and operating agreement between Consumers and the RTO, except to the extent necessary to resolve billing and other outstanding matters related to service rendered under this Agreement as specified in Section 2.5.

2.4Regulatory Filing

Transmission Provider shall file this Agreement with the Commission as a Service Agreement under the MISO Tariff, within the meaning of 18 C.F.R. Part 35. Consumers and Transmission Owner agree to cooperate with Transmission Provider with respect to such filing and to provide any information, including the rendering of testimony reasonably requested by Transmission Provider, needed to comply with applicable regulatory requirements.

2.5Survival

The applicable provisions of this Agreement shall continue in effect after expiration, cancellation, or termination hereof to the extent necessary to provide for final billings, billing adjustments, and the determination and enforcement of liability and indemnification obligations arising from acts or events that occurred while this Agreement was in effect.

ARTICLE 3

INTERCONNECTION SERVICE

3.1Scope of Service

In the event future changes in either (a) design or operation of any Unit, (b) Consumers’ requirements or (c) Transmission Provider’s or Transmission Owner’s requirements resulting from the Unit’s parallel operation with the Transmission System later necessitate additional Interconnection Assets or modifications to the then existing Interconnection Assets herein, the Parties shall undertake such additions and modifications as may be necessary. Before undertaking such future additions or modifications, the Parties shall consult, develop plans and coordinate schedules of activities, including the making of necessary amendments to this Agreement (including its Appendices) and/or entering into new agreements, so as to insure continuous and reliable operation of the Interconnection Assets. The cost of such additions or modifications to the Interconnection Assets shall be borne by Consumers unless otherwise agreed upon at the time. The ownership, operation and maintenance responsibilities for any such future additions or modifications shall be made consistent with the responsibilities allocated in this Agreement.

3.1.1Except as otherwise provided under Sections 5.8 and 5.9 of this Agreement, neither Transmission Provider nor Transmission Owner shall have an obligation under this Agreement to pay Consumers any wheeling or other charges for electric power and/or energy transferred through Consumers’ assets or for power or ancillary services provided by Consumers under this Agreement for the benefit of the Transmission System.

3.1.2Except as otherwise provided under this Agreement, neither Transmission Provider nor Transmission Owner shall have an obligation under this Agreement to make arrangements or pay under applicable tariffs for transmission and ancillary services associated with the delivery of electricity and ancillary electrical products produced by the Unit.

3.1.3Except as otherwise provided under this Agreement, neither Transmission Provider nor Transmission Owner shall have an obligation under this Agreement to procure electricity and ancillary electrical products to satisfy Consumers’ station power needs or other related requirements.

3.1.4Except as otherwise provided under this Agreement, neither Transmission Provider nor Transmission Owner shall have an obligation under this Agreement to make arrangements under applicable tariffs for transmission, losses, and ancillary services associated with the use of the Transmission System for the delivery of electricity and ancillary electrical products to the Unit.

3.1.5Transmission Provider makes no representations to Consumers regarding the availability of Transmission Service on the Transmission System, and Consumers agrees that the availability of Transmission Service on the Transmission System may not be inferred or implied from Transmission Provider’s or Transmission Owner’s execution of this Agreement. Consumers will obtain Transmission Service on the Transmission System under a separate agreement between the Parties and in accordance with the provisions of the MISO Tariff.

3.2Third-Party Actions

Consumers acknowledges and agrees that, from time to time during the term of this Agreement, other persons may develop, construct and operate, or acquire and operate generating assets in the Transmission Provider’s service territory, and construction or acquisition and operation of any such assets, and reservations by any such persons of Transmission Service under the MISO Tariff may adversely affect the Unit and the availability of Transmission Service for the Unit’s electric output. Consumers acknowledges and agrees that Transmission Provider has no obligation under this Agreement to disclose to Consumers any information with respect to third-party developments or circumstances, including the identity or existence of any such person or other assets, beyond what Transmission Provider customarily provides to other similarly situated generators, except as may be required under Article 4 of this Agreement and elsewhere in this Agreement. Consumers and Transmission Provider make no guarantees to the other under this Agreement with respect to Transmission Service that is available under the MISO Tariff.

ARTICLE 4

INTERCONNECTION ASSETS

4.1Reservation of Rights to Interconnection Assets

Except as provided in Section 5.2 hereof, each Party reserves to itself the ownership, operation and maintenance of its Interconnection Assets and all improvements, additions or extensions to its Interconnection Assets under this Agreement which are attributable to or necessitated by the interconnection of the Unit.

4.2Modifications

Either Party may undertake modifications to its assets. In the event a Party plans to undertake a modification that may be expected to impact the other Party's assets, that Party shall provide the other Party with sufficient information regarding such modification, including, without limitation, the notice required in accordance with Article 11 of this Agreement so that the other Party can evaluate the potential impact of such modification prior to commencement of the work. The Party desiring to perform such work shall provide the relevant drawings, plans, and specifications to the other Party at least ninety (90) days in advance of commencement of the work or such shorter period upon which the Parties may agree, which agreement will not unreasonably be withheld or delayed.

4.3As-Built Drawings

Upon execution of this Agreement, Consumers shall provide to Transmission Provider and Transmission Owner current interconnection drawings and system diagrams for each of its Units, unless the Parties agree that such drawings are not necessary. Subject to the requirements of Article 17 of this Agreement, not later than ninety (90) days after completion of any addition to or modification of the assets of any of said Units that may reasonably be expected to affect the Transmission System, Consumers shall issue revised "as built" drawings to Transmission Provider and Transmission Owner.

ARTICLE 5

OPERATIONS

5.1General

The Parties agree that they shall comply with the Operating Agreement, then-existing (or amended) applicable manuals, standards, and guidelines of Transmission Provider, NERC, ECAR, or any successor agency assuming or charged with similar responsibilities related to the operation and reliability of the North American electric interconnected transmission grid. To the extent that this Agreement does not specifically address or provide the mechanisms necessary to comply with such Operating Agreement, Transmission Provider, NERC or ECAR manuals, standards, or guidelines, the Parties hereby agree that each Party shall provide to the other Parties all such information as may reasonably be required to comply with such Operating Agreement, manuals, standards, or guidelines and shall operate, or cause to be operated, their respective assets in accordance with such Operating Agreement, manuals, standards, or guidelines.

5.2 Transmission Provider and Transmission Owner Obligations

Transmission Provider and Transmission Owner shall operate and control the Transmission System and other Transmission Owner assets in a safe and reliable manner (a) in accordance with Transmission Provider’s and Transmission Owner’s applicable operational and/or reliability criteria, protocols, and directives (which include those of NERC and ECAR), (b) the Operating Agreement and (c) in accordance with the provisions of this Agreement. From time to time, Consumers will control and operate four (4) 345 kV synchronizing circuit breakers (Nos. 28H9, 28R8, 32F7 and 32H9 in the Hampton Substation) to connect or disconnect the Karn 3 or Karn 4 Units, as the case may be, from the Transmission System. The Parties may agree from time to time that Consumers, under the direction of the Transmission Provider or Transmission Owner, will operate certain other Interconnection Assets of the Transmission Owner.

5.3Consumers Obligations

Consumers shall operate and control its Generation Resources in a safe and reliable manner in accordance with (a) Consumers’ applicable operational and/or reliability criteria, protocols, and directives (which shall include those of NERC and ECAR), the Operating Agreement and (c) the provisions of this Agreement.

5.4Jointly Owned Assets

Operation of Jointly Owned Assets at the electric substations where Interconnection Facilities are located will be under the direction and control of the Party with more than fifty percent (50%) of the major equipment at each such location, unless otherwise agreed by the Parties hereto. Said Party shall operate the Jointly Owned Assets in a manner consistent with Good Utility Practice and the provisions of Sections 5.2 and 5.3 above, as appropriate. Each Party’s respective share of responsibility for the costs of operation of Jointly Owned Assets shall be the same percentage as the percentage of major equipment owned by such Party in that substation, as set forth in Exhibit B and its subsequent addendum’s. The respective ownership of substation facilities is shown in the Wiring Diagrams for each of the electrical substations at which Consumers’ Generation Resources are connected to the Transmission System (see Exhibit B), reflecting ownership changes through July 24, 2008. The Wiring Diagrams (WDs) will be updated continuously in each Party’s Drawing Management System (DMS) which is shared between the Parties. For current ownership (reflecting ownership changes since July 24, 2008), see the WDs in the DMS. For purposes of this Agreement, major equipment is defined as (a) main power transformers, (b) 23 kV, 46 kV, 138 kV and 345 kV circuit breakers, (c) power system regulators and reclosers and (d) 46 kV and 138 kV capacitor banks (any three-phase installation of such equipment shall count as one unit of equipment). Exhibit B shall be updated with an addendum at least annually by the Transmission Owner, and approved in writing by all Parties at least annually, to show all changes in equipment and the effects of such changes on the determination of Jointly Owned Asset percentages. For purposes of this Section 5.4, such submission and approval of changes shall be in writing consistent with Section 21.1. In the case where each Party hereto owns exactly fifty percent (50%) of the major equipment at any specific location, the Transmission Owner shall assume the responsibility for direction and control of the operation activities as such location. In those substations where each Party hereto owns assets, each Party shall be responsible for its appropriate share, as set forth in Exhibit B hereto, of station power energy usage and expense.

5.5Access Rights

The Parties shall provide each other such access rights as may be necessary for either Party's performance of its respective operational obligations under this Agreement; provided that, notwithstanding anything stated herein, a Party performing operational work within the boundaries of the other Party's assets must abide by the rules applicable to that site.

5.6Switching and Tagging Rules

The Parties shall abide by their respective Switching and Tagging Rules for obtaining clearances for work or for switching operations on assets. The Parties will adopt mutually agreeable Switching and Tagging Rules prior to the effective date of this Agreement.

5.7 Black Start Participation

In accordance with Good Utility Practice, Consumers agrees to participate in Transmission Owner’s Black Start Plan, as well as any verification testing. Nothing in this Agreement obligates a particular Unit to provide Black Start Service.

5.8 Reactive Power

The supply and absorption of reactive power is dealt with in the Purchase and Sale Agreement for Ancillary Services among the Parties hereto.

5.9 System Security

During an Emergency on the Transmission System or on an adjacent transmission system, the System Operator has the authority to direct Consumers to increase or decrease real power production (measured in MW) and/or reactive power production (measured in MVAR), within the design and operational limitations of any of Consumers’ Generation Resources in service at the time, in order to maintain security on the Transmission System. In the event of such a declaration of an Emergency, determinations: (a) that the Transmission System security is in jeopardy, and/or (b) that there is a need to increase or decrease reactive power production, even if real power production is adversely affected, will be made solely by the System Operator or his designated representative. Each Unit operator will honor System Operator's orders and directives concerning said Unit’s real power and/or reactive power output within design and operational limitations of the Unit's equipment in service at the time, such that the security of the Transmission System is maintained. Transmission Provider and Transmission Owner shall restore the Transmission System conditions to normal to alleviate any such Emergency, in accordance with Good Utility Practice. Consumers will be compensated by Transmission Provider or Transmission Owner for increasing or decreasing the real power output of any of its Units as directed by the System Operator to support the Transmission System during an Emergency by the payment of (a) Consumers’ Incremental Cost associated with such increase or decrease in real power output or (b) at such other rate filed by a Party and approved by the Commission including any existing tariff or rate schedule which has been filed by the Transmission Provider, Transmission Owner or Consumers. Similarly, if the Transmission Provider or Transmission Owner requests any of Consumers’ Units to provide or

absorb reactive power that would be outside of the Unit’s Reactive Design Limitations, requiring the Unit’s real power output to be reduced to obtain the desired reactive power, the Transmission Provider or Transmission Owner shall compensate Consumers at the real power rate discussed in the preceding sentence, to the extent that the Unit had to reduce real power output to operate within its Reactive Design Limitations, unless otherwise provided in another agreement or tariff on file with the Commission.

5.10Consumers Voltage Regulation

Consumers shall have sufficient voltage regulation at each Unit to maintain an acceptable voltage level for the equipment at the Unit during periods of time that the Unit’s generation is off line.

5.11Protection and System Quality

Consumers shall, at its expense, install, maintain, and operate System Protection Assets, including such protective and regulating devices as are identified by order, rule or regulation of any duly constituted regulatory authority having jurisdiction, or as are otherwise necessary to protect personnel and assets and to minimize deleterious effects to Transmission Provider’s or Transmission Owner’s electric service operation arising from the Unit. Transmission Owner shall install any such protective or regulating devices that may be required on Transmission Owner’s assets in connection with the operation of the Unit at Consumers’ expense.

5.11.1Requirements for Protection. In compliance with applicable NERC, ECAR and Transmission Provider’s and Transmission Owner’s requirements, Consumers shall provide, own, and maintain relays, circuit breakers and all other devices necessary to promptly remove any fault contribution of the Unit to any short circuit occurring on the Transmission System not otherwise isolated by Transmission Owner’s assets. Such protective assets shall include, without limitation, a disconnecting device or switch with visible blade disconnect and load interrupting capability to be located between the Unit and the Transmission System at an accessible, protected, and satisfactory site selected upon mutual agreement of the Parties. The present integrated system provides for fault clearing at the generation substations. Unit protection may not be able to detect all short circuits, but the Parties agree that no other arrangements shall be required. Consumers shall be responsible for protection of the Unit and Consumers’ other associated assets from such conditions as negative sequence currents, over- or under-frequency, sudden load rejection, over- or under-voltage, and generator loss-of-field. Consumers shall be solely responsible for provisions to disconnect the Unit and Consumers’ other associated assets when any of the disturbances described above occur on the Transmission System.

5.11.2System Power Quality. Consumers’ facilities and equipment shall not cause excessive voltage flicker nor introduce excessive distortion to the sinusoidal voltage or current waves. Power output from and input to the Unit shall be in accordance with the power quality standards contained in IEEE Standards 141 - Recommended Practice for Electrical Power Distribution for Industrial Plants (voltage flicker) and 519 - Recommended Practices and Requirements for Harmonic Control in Electric Power Systems (harmonics). Consumers’ facilities and equipment have been designed and constructed in accordance with then-existing standards so as not to cause excessive voltage excursions nor cause the voltage to drop below or rise above the range maintained by Transmission Provider or Transmission Owner in the absence of Consumers’ facilities and equipment at the time the Unit first went into service.

5.11.3Inspection. Subject to the confidentiality provisions set forth in Article 17, Transmission Provider and Transmission Owner shall have the right, but shall have no obligation or responsibility to (a) observe Consumers’ tests and/or inspection of any of Consumers’ protective assets directly connected to the Transmission System or interfacing with Transmission Owner’s protective assets, (b) review the settings of any of Consumers’ protective assets; and (c) review Consumers’ maintenance records relative to Consumers’ protective assets. Transmission Provider and Transmission Owner may exercise the foregoing rights from time to time as deemed necessary by Transmission Provider or Transmission Owner upon reasonable notice to Consumers. However, the exercise or non-exercise by Transmission Provider or Transmission Owner of any of the foregoing rights of observation, review or inspection shall be construed neither as an endorsement or confirmation of any aspect, feature, element, or condition of the Unit or Consumers’ protective assets or the operation thereof, nor as a warranty as to the fitness, safety, desirability, or reliability of same.

5.12Outages, Interruptions, and Disconnection

5.12.1Outage Authority and Coordination. In accordance with Good Utility Practice, each Party may, in close cooperation with the other and upon providing notice per Section 20.2, remove from service its assets that may impact the other Party's assets as necessary to perform maintenance or testing or to install or replace assets. Absent the existence or imminence of an Emergency, the Party scheduling a removal of a facility from service will schedule such removal on a date mutually acceptable to both Parties. Further, the Transmission Provider and Transmission Owner shall use their best efforts to coordinate the scheduling of maintenance on Transmission Owner’s Interconnection Assets to coincide with Consumers scheduled maintenance on its Units that may be impacted by maintenance on Transmission Owner’s Interconnection Assets.

5.12.2Outage Restoration.

5.12.2.1Unplanned Outage. In the event of an unplanned outage of a Party's facility that adversely affects the other Party's assets, the Party that owns or controls the facility out of service will use commercially reasonable efforts to promptly restore that facility to service.

5.12.2.2Planned Outage. In the event of a planned outage of a Party's facility that adversely affects the other Party's assets, the Party that owns or controls the facility out of service will use commercially reasonable efforts to promptly restore that facility to service and in accordance with its schedule for the work that necessitated the planned outage.

5.12.3Interruption. If at any time, in Transmission Provider’s or Transmission Owner’s reasonable judgment, the continued operation of the Unit would cause an Emergency, Transmission Provider or Transmission Owner may curtail, interrupt, or reduce energy delivered from the Unit to the Transmission System until the condition which would cause the Emergency is corrected. Transmission Provider or Transmission Owner shall give Consumers as much notice as is reasonably practicable of Transmission Provider’s or Transmission Owner’s intention to curtail, interrupt, or reduce energy delivery from the Unit in response to a condition that would cause an Emergency and, where practicable, allow suitable time for the Parties to remove or remedy such condition before any such curtailment, interruption, or reduction commences. In the event of any curtailment, interruption, or reduction, Transmission Provider or Transmission Owner shall promptly

confer with Consumers regarding the conditions that gave rise to the curtailment, interruption, or reduction, and Transmission Provider or Transmission Owner shall give Consumers Transmission Provider’s or Transmission Owner’s recommendation, if any, concerning the timely correction of such conditions. Transmission Provider or Transmission Owner shall promptly cease the curtailment, interruption, or reduction of energy delivery when the condition that would cause the Emergency ceases to exist.

5.12.4Disconnection.

5.12.4.1Disconnection after Agreement Terminates. Upon termination of the Agreement, Transmission Provider or Transmission Owner may disconnect Consumers’ Generation Resources from the Transmission System in accordance with a plan for disconnection upon which the Parties agree.

5.12.4.2Disconnection in Event of Emergency. Subject to the provisions of Subsection 5.12.4.3 of this Agreement, Transmission Provider, Transmission Owner or Consumers shall have the right to disconnect the Unit without notice if, in Transmission Provider’s, Transmission Owner’s or Consumers’ sole opinion, an Emergency exists and immediate disconnection is necessary to protect persons or property from damage or interference caused by Consumers’ interconnection or lack of proper or properly operating protective devices. For purposes of this Subsection 5.12.4.2, protective devices may be deemed by Transmission Provider or Transmission Owner to be not properly operating if Transmission Provider’s or Transmission Owner’s review under Article 6 of this Agreement has disclosed irregular or otherwise insufficient maintenance on such devices or that maintenance records do not exist or are otherwise insufficient to demonstrate that adequate maintenance has been and is being performed.

5.12.4.3Disconnection after Under-frequency Load Shed Event. NERC Planning Criteria require the interconnected transmission system frequency be maintained between 59.95 Hz and 60.05 Hz. In case of an under-frequency system disturbance, the Transmission System is designed to automatically activate a five-tier load shed program. The five load sheds occur at 59.5, 59.3, 59.1, 58.9 and 58.7 Hz, respectively. For those Units that are determined by Transmission Provider to be large enough to impact the Transmission Provider’s system security, each such Unit shall be capable of under-frequency operation as specified in Appendix 1 “Isolation of Generating Units” contained in ECAR Document No. 3 - Emergency Operations, or a higher under-frequency set point if already in place upon execution of this Agreement. Upon notice from Consumers and if the Transmission Provider or Transmission Owner agrees, Consumers may implement a higher under-frequency relay set point if necessary to protect its assets for a particular Unit or Units.

5.12.5Continuity of Service. Notwithstanding any other provision of this Agreement, Transmission Provider shall not be obligated to accept, and Transmission Provider may require Consumers to curtail, interrupt or reduce deliveries of energy if such delivery of energy impairs Transmission Provider’s or Transmission Owner’s ability to construct, install, repair, replace or remove any of its equipment or any part to its system or if Transmission Provider or Transmission Owner determines that curtailment, interruption or reduction is necessary because of Emergencies, forced outages, operating conditions on its system, or any reason otherwise permitted by applicable rules or regulations promulgated by a regulatory agency having jurisdiction over such matters. The Parties shall coordinate, and if necessary negotiate in good faith, the timing of such curtailments,

interruptions, reductions or deliveries with respect to maintenance, investigation or inspection of Transmission Owner’s assets or system. Consumers reserves all rights under the Federal Power Act and applicable other federal and state laws and regulations to commence a complaint proceeding or other action with the Commission or other Governmental Authority with appropriate jurisdiction over the Parties to enforce the provisions of this Subsection 5.12.5.

5.12.6Curtailment Notice. Except in case of Emergency, in order not to interfere unreasonably with the other Party's operations, the curtailing, interrupting or reducing Party shall give the other Party reasonable prior notice of any curtailment, interruption or reduction, the reason for its occurrence, and its probable duration.

5.13Operating Expenses

Consumers shall reimburse Transmission Owner for all direct and indirect costs and expenses (including but not limited to telephone circuit charges, property taxes, insurance and assets testing) incurred by Transmission Owner in operating Transmission Owner’s Interconnection Assets, to the extent that Transmission Owner is not otherwise recovering such costs and expenses under an existing tariff or rate schedule which has been filed by Transmission Provider or Transmission Owner and accepted by FERC. Such costs and expenses shall be determined by Transmission Owner in accordance with the standard practices and policies followed by Transmission Provider or Transmission Owner for the performance of work for others in effect at the time such operation work is performed. Payment by Consumers shall be made in accordance with the provisions of Article 12 hereof.

ARTICLE 6

MAINTENANCE

6.1Transmission Owner’s Obligations

Transmission Owner shall maintain its assets, to the extent they might reasonably be expected to have an impact on the operation of the Unit (a) in a safe and reliable manner in accordance with applicable operational and/or reliability criteria, protocols, and directives (which include those of NERC and ECAR), (b) in accordance with the provisions of the Operating Agreement and (c) in accordance with the provisions of this Agreement.

6.2Consumers’ Obligations

Consumers shall maintain its assets, to the extent they might reasonably be expected to have an impact on the operation of the Transmission System (a) in a safe and reliable manner in accordance with applicable operational and/or reliability criteria, protocols, and directives (which include those of NERC and ECAR), (b) in accordance with the provisions of the Operating Agreement and (c) in accordance with the provisions of this Agreement.

6.3Jointly Owned Assets

Maintenance of Jointly Owned Assets at the electric substations where Interconnection Facilities are located will be under the direction and control of the Party with more than fifty percent (50%) of the major equipment at each such location, unless otherwise agreed by the Parties hereto. Said Party shall maintain the Jointly Owned Assets in a manner consistent with Good Utility Practice

and the provisions of Sections 6.1 and 6.2 above, as appropriate. Each Party’s respective share of responsibility for the costs of maintenance of Jointly Owned Assets shall be the same percentage as the percentage of major equipment owned by such Party in that substation, as set forth in Exhibit B and its subsequent addendum. For purposes of this Agreement, major equipment is defined as set forth in Section 5.4 hereto. Exhibit B shall be updated with an addendum at least annually by the Transmission Owner, and approved in writing by Consumers, to show all changes in equipment and the effects of such changes on the determination of Jointly Owned Asset percentages. In the case where each Party hereto owns exactly fifty percent (50%) of the major equipment at any specific location, the Transmission Owner shall assume the responsibility for direction and control of the maintenance activities at such location.

6.4Access Rights

The Parties shall provide each other such access rights as may be necessary for either Party's performance of their respective maintenance and/or construction obligations under this Agreement; provided that, notwithstanding anything stated herein, a Party performing maintenance and/or construction work within the boundaries of the other Party's assets must abide by the rules applicable to that site.

6.5Maintenance Expenses

Consumers shall reimburse Transmission Owner for all direct and indirect costs and expenses (including but not limited to inspection, repair and replacement) incurred by Transmission Owner in maintaining Transmission Owner’s Interconnection Assets, to the extent that Transmission Owner is not otherwise recovering such costs and expenses under an existing tariff or rate schedule which has been filed by Transmission Provider or Transmission Owner and accepted by FERC. Such costs and expenses shall be determined by Transmission Owner in accordance with the standard practices and policies followed by Transmission Provider or Transmission Owner for the performance of work for others in effect at the time such operation work is performed. Payment by Consumers shall be made in accordance with the provisions of Article 12 of this Agreement.

6.6Coordination

The Parties agree to confer regularly to coordinate the planning and scheduling of preventative and corrective maintenance. Each Party shall conduct preventive and corrective maintenance activities as planned and scheduled in accordance with this Section 6.5 and the Operating Agreement.

6.7Inspections and Testing

Each Party shall perform routine inspection and testing of its assets in accordance with Good Utility Practice as may be necessary to ensure the continued interconnection of each Unit with the Transmission System in a safe and reliable manner.

6.8Right to Observe Testing

Each Party shall, at its own expense, have the right to observe the testing of any of the other Party's assets whose performance may reasonably be expected to affect the reliability of the

observing Party's assets. Each Party shall notify the other Party in advance of its performance of tests of its assets, and the other Party may have a representative attend and be present during such testing.

6.9Secondary Systems

Each Party agrees to cooperate with the other in the inspection, maintenance, and testing of those Secondary Systems directly affecting the operation of a Party's assets which may reasonably be expected to impact the other Party. Each Party will provide advance notice to the other Party before undertaking any work in these areas, especially in electrical circuits involving circuit breaker trip and close contacts, current transformers, or potential transformers.

6.10Observation of Deficiencies

If a Party observes any deficiencies or defects on, or becomes aware of a lack of scheduled maintenance and testing with respect to, the other Party's assets that might reasonably be expected to adversely affect the observing Party's assets, the observing Party shall either (a) provide notice to the other Party that is prompt under the circumstance or (b) deem such observation an Emergency to life or property and immediately disconnect the Unit pursuant to Subsection 5.12.4.2 of this Agreement, and the other Party shall make any corrections required in accordance with Good Utility Practice.

ARTICLE 7

EMERGENCIES

7.1Obligations

Each Party agrees to comply with NERC and ECAR Emergency procedures and Transmission Provider, Transmission Owner and Consumers Emergency procedures, as applicable, with respect to Emergencies.

7.2Notice

Transmission Provider or Transmission Owner shall provide Consumers with oral notification that is prompt under the circumstances of an Emergency that may reasonably be expected to affect Consumers’ operation of any or all of its Generation Resources, to the extent Transmission Provider or Transmission Owner is aware of the Emergency. Consumers shall provide Transmission Provider and Transmission Owner with oral notification that is prompt under the circumstances of an Emergency that may reasonably be expected to affect the Transmission System, to the extent Consumers is aware of the Emergency. In lieu of oral notification described in the preceding two sentences, the Parties may agree in advance to use other electronic notification means. To the extent the Party becoming aware of an Emergency is aware of the facts of the Emergency, such notification shall describe the Emergency, the extent of the damage or deficiency, its anticipated duration, and the corrective action taken and/or to be taken. Any such notification given pursuant to this Section 7.2 shall be followed as soon as practicable with written notice.

7.3Immediate Action

In case of an Emergency, the Party becoming aware of the Emergency may, in accordance with Good Utility Practice, take such action as is reasonable and necessary to prevent, avoid, or mitigate injury, danger, and loss, including disconnection pursuant to Subsection 5.12.4.2 of this Agreement.

7.4Transmission Provider’s and Transmission Owner’s Authority

Transmission Provider or Transmission Owner may, consistent with Good Utility Practice, take whatever actions with regard to the Transmission System as it may deem necessary during an Emergency in order to (a) preserve public health and safety, (b) preserve the reliability of the Transmission System, (c) limit or prevent damage and (d) expedite restoration of service. Transmission Provider or Transmission Owner shall use reasonable efforts to minimize the effect of such actions on the Unit.

7.5Consumers’ Authority

Consumers may, consistent with Good Utility Practice, take whatever actions with regard to the Unit as it may deem necessary during an Emergency in order to (a) preserve public health and safety, (b) preserve the reliability of the Unit, (c) limit or prevent damage and (d) expedite restoration of service. Consumers shall use reasonable efforts to minimize the effect of such actions on the Transmission System.

7.6Audit Rights

Each Party shall keep and maintain records of actions taken during an Emergency that may reasonably be expected to impact the other Party's assets and make such records available for third-party independent audit upon the request and expense of the party affected by such action. Any such request for an audit will be no later than twelve (12) months following the action taken.

ARTICLE 8

SAFETY

8.1General

The Parties agree that all work performed by a Party that may reasonably be expected to affect another Party shall be performed in accordance with Good Utility Practice and all applicable laws, regulations, and other requirements pertaining to the safety of persons or property. A Party performing work within the boundaries of another Party’s assets must abide by the safety rules applicable to the site.

8.2Environmental Releases

Each Party shall notify the other Parties, first orally and then in writing, of the release of any Hazardous Substances or any type of remedial activities, such as asbestos or lead abatement, which may reasonably be expected to affect another Party, as soon as possible but not later than twenty-four (24) hours after the Party becomes aware of the occurrence, and shall promptly furnish to the other Parties copies of any reports filed with any governmental agencies addressing such events.

ARTICLE 9

METERING

9.1General

Transmission Owner shall provide, install, own and maintain Metering Assets necessary to meet its obligations under this Agreement. Notwithstanding the foregoing sentence, Consumers, if mutually agreed by the Parties, may provide and install some, or all, of said Metering Assets, as per Transmission Owner’s specifications. The Parties agree that, as to all Connection Points in existence as of the effective date of this Agreement, no new Metering Assets or arrangements shall be required. If necessary, Metering Assets shall be either located or adjusted, at Transmission Provider’s or Transmission Owner’s option, in such manner to account for (a) any transformation or interconnection losses between the location of the meter and the Point of Receipt and (b) any station auxiliary power load of the generating unit. Metering quantities, in analog and/or digital form, shall be provided to Consumers upon request. The Parties also agree that Consumers shall continue to maintain records of the Megawatthour and Megavarhour values collected from existing meters on the generating units and provide the information recorded to Transmission Provider or Transmission Owner upon request.

9.2Costs of Administering Metering Assets

All costs associated with the administration of Metering Assets and the provision of metering data to Consumers shall be born by Consumers. The costs of administration and of providing metering data shall be separately itemized on Transmission Owner’s invoices to Consumers pursuant to Article 12 of this Agreement. All costs associated with changes to Metering Assets requested by Consumers, shall be borne by Consumers and shall be invoiced pursuant to Article 12 of this Agreement.

9.3Testing of Metering Assets

Transmission Owner shall, at Consumers’ expense, inspect and test all Metering Assets not less than once every year, unless an extension of the testing cycle is agreed upon by the Parties. If requested to do so by Consumers and at Consumers’ expense, Transmission Owner shall inspect or test Metering Assets more frequently. Transmission Owner shall give reasonable notice of the time when any inspection or test shall take place and Consumers may have representatives present at the test or inspection. If Metering Assets is found to be inaccurate or defective, it shall be adjusted, repaired or replaced at Consumers’ expense, in order to provide accurate metering. If Metering Assets fails to register, or if the measurement made by Metering Assets during a test varies by more than two percent (2%) from the measurement made by the standard Metering Assets used in the test, adjustment shall be made correcting all measurements made by the inaccurate Metering Assets for (a) the actual period during which inaccurate measurements were made, if the period can be determined, or (b) a period equal to one-half of the elapsed time since the last test of the Metering Assets.

9.4Metering Data

9.4.1When the Metering Assets location is not at the Point of Receipt, Metering Assets readings shall be adjusted to account for appropriate transformer and line losses, and when

applicable, the station auxiliary power load of the Unit.

9.4.2At Consumers’ expense, all metered data shall be telemetered to one or more locations designated by Transmission Provider and one or more locations designated by Consumers.

9.5Communications

9.5.1At Consumers’ expense, Consumers shall maintain satisfactory operating communications with System Operator or representative, as designated by Transmission Provider or Transmission Owner. Consumers has provided standard voice and facsimile communications in the control room of each of its Units through use of the public telephone system. Consumers has also provided a 4-wire, full duplex data circuit (or circuits) operating at a minimum of 9600 baud, or at other baud rates as reasonably specified by Transmission Provider or Transmission Owner. The data circuit(s) extend from each Consumers’ Unit to a location, or locations, specified by Transmission Provider or Transmission Owner. Any required maintenance of such communications assets shall be performed at Consumers’ expense, and may be performed by Consumers or by Transmission Owner. Operational communications shall be activated and maintained under, but not be limited to, the following events: system paralleling or separation, scheduled and unscheduled shutdowns, equipment clearances, and hourly and daily load data exchanges. To the extent required by applicable rules and regulations, Consumers shall (a) request permission from the System Operator prior to opening or closing circuit breakers that affect the Transmission System, (b) carry out switching orders from the System Operator in a timely manner and (c) keep the System Operator advised of the Unit’s operational capabilities as required for reliable operation of the Transmission System.

9.5.2For all Units 1 MW or larger, a Remote Terminal Unit ("RTU"), or equivalent data collection and transfer equipment acceptable to Consumers and Transmission Owner, has been installed to gather accumulated and instantaneous data to be telemetered to a location, or locations, designated by Transmission Owner through use of dedicated point-to-point data circuits as indicated in Subsection 9.5.1 of this Agreement. Instantaneous bi-directional analog real power and reactive power flow information, circuit breaker status information, instantaneous analog voltage information, metering information, and disturbance monitoring information, as determined by Transmission Provider or Transmission Owner, must be telemetered directly to the location, or locations, specified by Transmission Provider or Transmission Owner.

ARTICLE 10

FORCE MAJEURE

10.1An event of Force Majeure means any act of God, labor disturbance, act of the public enemy, war, insurrection, riot, fire, storm or flood, explosion, breakage or accident to machinery or assets, any curtailment, order, regulation or restriction imposed by governmental military or lawfully established civilian authorities, or any other cause beyond a Party's reasonable control. A Force Majeure event does not include an act of negligence or intentional wrongdoing.

10.2If either Party is rendered unable, wholly or in part, by Force Majeure, to carry out its obligations under this Agreement, then, during the continuance of such inability, the obligation of

such Party shall be suspended except that Consumers’ obligation under Section 5.11 of this Agreement to provide protection while operating in parallel with the Transmission System shall not be suspended. The Party relying on Force Majeure shall give written notice of Force Majeure to the other Party as soon as practicable after such event occurs. Upon the conclusion of Force Majeure, the Party heretofore relying on Force Majeure shall, with all reasonable dispatch, take all necessary steps to resume the obligation previously suspended.

10.3Any Party’s obligation to make payments already owing shall not be suspended by Force Majeure.

ARTICLE 11

INFORMATION REPORTING

Each Party shall, in accordance with Good Utility Practice, promptly provide to the other Parties all relevant information, documents, or data regarding the Party's assets which may reasonably be expected to pertain to the reliability of the other Parties’ assets and/or which has been reasonably requested by the other Parties.

ARTICLE 12

PAYMENTS AND BILLING PROCEDURES

12.1Invoices

Any invoices for reimbursable services provided to another Party under this Agreement during the preceding month shall be prepared within a reasonable time after the first day of each month. Each invoice shall delineate the month in which services were provided, shall fully describe the services rendered and shall be itemized to reflect the services performed or provided. The invoice shall be paid so that the other Party will receive the funds by the 20^th day following the date of such invoice, or the first business day thereafter if the payment date falls on other than a business day. All payments shall be made in immediately available funds payable to another Party, or by wire transfer to a bank named by the Party being paid, provided that payments expressly required by this Agreement to be mailed shall be mailed in accordance with Section 12.2.

12.2Payments

Any payments to be made by Consumers under this Agreement shall be made to Transmission Owner at the following address:

Michigan Electric Transmission Company, LLC

P.O. Box 673971

Detroit, MI 48267-3971

Attn: Accounting Department

If paying by wire transfer, please see the wiring instructions on the invoice.

Any payments to be made by Transmission Owner under this Agreement shall be made to Consumers at the following address:

Consumers Energy Company

One Energy Plaza

Jackson, Michigan 49201

Attn: Treasurer

The Parties shall provide the names of appropriate contact personnel, as are set forth in this Agreement or otherwise, to each other after this Agreement is executed and shall keep said listing of names and addresses up to date.

12.3Interest Charges

Interest on any unpaid amounts shall be calculated in accordance with the methodology specified for interest on refunds in the Commission’s regulations at 18 CFR. §35.19 (a)(2)(iii). Interest on delinquent amounts shall be calculated from the due date of the invoice to the date of payment. When payments are made by mail, invoices shall be considered as having been paid on the date of receipt by Transmission Owner or Consumers, as the case may be.

12.4Disputes

In the event of a billing dispute between Transmission Owner and Consumers, the Parties shall continue to provide services and pay all invoiced amounts not in dispute. While the dispute is being resolved, the Parties shall continue to provide services and pay all invoiced amounts not in dispute. Following resolution of the dispute, the prevailing Party shall be entitled to receive the disputed amount, as finally determined to be payable, along with interest accrued through the date on which payment is made at the interest rate pursuant to Section 13.3. Payment shall be due within ten (10) days of resolution.

ARTICLE 13

ASSIGNMENT

13.1This Agreement shall inure to the benefit of and be binding upon the successors and assigns of the respective parties hereto. This Agreement shall not be transferred or otherwise alienated by any Party without the other Parties' prior written consent, which consent shall not be unreasonably withheld, provided that any assignee shall expressly assume assignor's obligations hereunder and, unless expressly agreed to by the other Parties, no assignment shall relieve the assignor of its obligations hereunder in the event its assignee fails to perform. Any attempted assignment, transfer or other alienation without such consent shall be void and not merely voidable.

13.2Notwithstanding the above, the Transmission Provider or Transmission Owner shall be permitted to assign or otherwise transfer this Agreement, or its rights, duties and obligations hereunder, in whole or in part, by operation of law or otherwise, without the prior written consent of Consumers, to any successor to or transferee of the direct or indirect ownership or operation of all or part of the transmission system to which the Generation Resources are connected. Upon the assumption by any such permitted assignee of the assigning Transmission Provider’s or Transmission Owner’s rights, duties and obligations hereunder, the assigning Transmission Provider or Transmission Owner shall be released and discharged therefrom to the extent provided in the assignment agreement.

13.3Notwithstanding the above, Consumers may assign this Agreement to a bank pursuant to the terms of an Assignment and Security Agreement without the prior written consent of

Transmission Provider or Transmission Owner provided that such assignment shall not be effective as to Transmission Provider or Transmission Owner until it receives a fully executed copy thereof.

ARTICLE 14

INDEMNITY AND INSURANCE

14.1Indemnity

The Parties shall at all times assume all liability for, and shall indemnify and save the other Parties harmless from any and all damages, losses, claims, demands, suits, recoveries, costs, legal fees, expenses for injury to or death of any person or persons whomsoever, or for any loss, destruction of or damage to any property of third persons, firms, corporations or other entities that occurs on its own system and that arises out of or results from, either directly or indirectly, its own assets or assets controlled by it, unless caused by the sole negligence, or intentional wrongdoing, of another Party.

14.2Insurance

14.2.1The Parties agree to maintain, at their own cost and expense, the following insurance coverages for the life of this Agreement in the manner and amounts, at a minimum, as set forth below:

(a) Workers’ Compensation Insurance in accordance with all applicable State, Federal, and Maritime Law.

(b) Employer’s Liability insurance in the amount of $1,000,000 per accident.

(c) Commercial General Liability or Excess Liability Insurance in the amount of $25,000,000 per occurrence.

(d) Automobile Liability Insurance for all owned, non-owned, and hired vehicles in the amount of $5,000,000 each accident.

14.2.2A Party may, at its option, [A] be an approved self-insurer for the insurances required in 1.(a) and (d); and [B] maintain such deductibles and/or retentions under the insurance required in 1.(b) and (c) as is maintained by other similarly situated companies engaged in a similar business. The Parties agree that all amounts of self-insurance, retentions and/or deductibles are the responsibility of, and shall be borne by, the Party whom makes such an election.

14.2.3Within fifteen (15) days of the Effective Date and thereafter when requested, in writing, but not more than once every 12 months, during the term of this Agreement (including any extensions) each Party shall provide to the other Parties properly executed and current certificates of insurance or evidence of approved self-insurance status with respect to all insurance required

to be maintained by such Party under this Agreement. Certificates of insurance shall provide the following information:

(a) Name of insurance company, policy number and expiration date.

(b) The coverage maintained and the limits on each, including the amount of deductibles or retentions, which shall be for the account of the Party maintaining such policy.

(c) The insurance company shall endeavor to provide thirty (30) days prior written notice of cancellation to the certificate holder.

ARTICLE 15

LIMITATION ON LIABILITY

NO PARTY SHALL IN ANY EVENT BE LIABLE TO THE OTHER PARTIES FOR ANY SPECIAL, INCIDENTAL, EXEMPLARY, PUNITIVE OR CONSEQUENTIAL DAMAGES SUCH AS, BUT NOT LIMITED TO, LOST PROFITS, REVENUE OR GOOD WILL, INTEREST, LOSS BY REASON OF SHUTDOWN OR NON-OPERATION OF EQUIPMENT OR MACHINERY, INCREASED EXPENSE OF OPERATION OF EQUIPMENT OR MACHINERY, COST OF PURCHASED OR REPLACEMENT POWER OR SERVICES OR CLAIMS BY CUSTOMERS, WHETHER SUCH LOSS IS BASED ON CONTRACT, WARRANTY, NEGLIGENCE, STRICT LIABILITY OR OTHERWISE.

ARTICLE 16

BREACH, CURE AND DEFAULT

16.1General

A breach of this Agreement ("Breach") shall occur upon the failure by a Party to perform or observe any material term or condition of this Agreement. Default of this Agreement ("Default") shall occur upon the failure of a Party in Breach of this Agreement to cure such Breach in accordance with the provisions of Section 16.4 of this Agreement.

16.2Events of Breach

A Breach of this Agreement shall include:

16.2.1The failure to pay any amount when due;

16.2.2The failure to comply with any material term or condition of this Agreement, including but not limited to any material Breach of a representation, warranty or covenant made in this

Agreement;

16.2.3If a Party: (a) becomes insolvent; (b) files a voluntary petition in bankruptcy under any provision of any federal or state bankruptcy law or shall consent to the filing of any bankruptcy or reorganization petition against it under any similar law; (c) makes a general assignment for the benefit of its creditors or (d) consents to the appointment of a receiver, trustee or liquidator;

16.2.4Assignment of this Agreement in a manner inconsistent with the terms of this Agreement;

16.2.5Failure of a Party to provide such access rights, or a Party's attempt to revoke or terminate such access rights, as provided under this Agreement; or

16.2.6Failure of a Party to provide information or data to the other Parties as required under this Agreement, provided the Party entitled to the information or data under this Agreement requires such information or data to satisfy its obligations under this Agreement.

16.3Continued Operation

In the event of a Breach or Default by a Party, the Parties shall continue to operate and maintain, as applicable, such DC power systems, protection and Metering Assets, Telemetering Assets, SCADA equipment, transformers, Secondary Systems, communications assets, building assets, software, documentation, structural components, and other assets and appurtenances that are reasonably necessary for Transmission Provider or Transmission Owner to operate and maintain the Transmission System and for Consumers to operate and maintain the Unit, in a safe and reliable manner.

16.4Cure and Default

Upon the occurrence of an event of Breach, the Party or Parties not in Breach (hereinafter the "Non-Breaching Party"), when it becomes aware of the Breach, shall give written notice of the Breach to the Breaching Party and to any other person the Parties to this Agreement identify in writing to the other Parties in advance. Such notice shall set forth, in reasonable detail, the nature of the Breach, and where known and applicable, the steps necessary to cure such Breach. Upon receiving written notice of the Breach hereunder, the Breaching Party shall have thirty (30) days to cure such Breach. If the Breach is such that it cannot be cured within thirty (30) days, the Breaching Party will commence in good faith all steps as are reasonable and appropriate to cure the Breach within such thirty (30) day time period and thereafter diligently pursue such action to completion. In the event the Breaching Party fails to cure the Breach, or to commence reasonable and appropriate steps to cure the Breach, within thirty (30) days of becoming aware of the Breach; the Breaching Party will be in Default of the Agreement.

16.5Right to Compel Performance

Notwithstanding the foregoing, upon the occurrence of an event of Default, the non-Defaulting Party or Parties shall be entitled to: (a) commence an action to require the Defaulting Party to remedy such Default and specifically perform its duties and obligations hereunder in accordance with the terms and conditions hereof and (b) exercise such other rights and remedies as it may have in equity or at law.

ARTICLE 17

CONFIDENTIALITY

17.1All information regarding a Party (the “Disclosing Party”) that is furnished directly or indirectly to the another Party (the “Recipient”) pursuant to this Agreement and marked “Confidential” shall be deemed “Confidential Information”. Notwithstanding the foregoing, Confidential Information does not include information that (i) is rightfully received by Recipient from a third party having an obligation of confidence to the Disclosing Party, (ii) is or becomes in the public domain through no action on Recipient’s part in violation of this Agreement, (iii) is already known by Recipient as of the date hereof, or (iv) is developed by Recipient independent of any Confidential Information of the Disclosing Party. Information that is specific as to certain data shall not be deemed to be in the public domain merely because such information is embraced by more general disclosure in the public domain.

17.1.1Recipient shall keep all Confidential Information strictly confidential and not disclose any Confidential Information to any third party for a period of two (2) years from the date the Confidential Information was received by Recipient, except as otherwise provided herein.

17.1.2Recipient may disclose the Confidential Information to its affiliates and its affiliates’ respective directors, officers, employees, consultants, advisors, and agents who need to know the Confidential Information for the purpose of assisting Recipient with respect to its obligations under this Agreement. Recipient shall inform all such parties, in advance, of the confidential nature of the Confidential Information. Recipient shall cause such parties to comply with the requirements of this Agreement and shall be responsible for the actions, uses, and disclosures of all such parties.

17.1.3If Recipient becomes legally compelled or required to disclose any of the Confidential Information (including, without limitation, pursuant to the policies, methods, and procedures of the FERC, including the OASIS Standards of Conduct, or other Regulatory Authority), Recipient will provide the Disclosing Party with prompt written notice thereof so that the Disclosing Party may seek a protective order or other appropriate remedy. Recipient will furnish only that portion of the Confidential Information which its counsel considers legally required, and Recipient will cooperate, at the Disclosing Party’s expense, with the Disclosing Party’s counsel to enable the Disclosing Party to obtain a protective order or other reliable assurance that confidential treatment will be accorded the Confidential Information. It is further agreed that, if, in the absence of a protective order, Recipient is nonetheless required to disclose any Confidential Information, Recipient will furnish only that portion of the Confidential Information which its counsel considers legally required.

ARTICLE 18

AUDIT RIGHTS

Subject to the requirements of confidentiality under Article 17 of this Agreement, each Party shall have the right, during normal business hours, and upon prior reasonable notice to another Party, to audit one another's accounts and records pertaining to the Party's performance and/or

satisfaction of obligations arising under this Agreement. Said audit shall be performed at the offices where such accounts and records are maintained and shall be limited to those portions of such accounts and records that relate to obligations under this Agreement.

ARTICLE 19

DISPUTES

The Dispute Resolution Procedures set forth in the MISO Tariff shall apply to all disputes arising under this Agreement.

ARTICLE 20

NOTICES

20.1Any notice, demand or request required or permitted to be given by a Party to another and any instrument required or permitted to be tendered or delivered by a Party to another may be so given, tendered or delivered, as the case may be, by depositing the same in any United States Post Office with postage prepaid, for transmission by certified or registered mail, addressed to the Party, or personally delivered to the Party, at the address set out below:

To Transmission Owner:

Michigan Electric Transmission Company, LLC

27175 Energy Way

Novi, MI 48377

Attn: Legal Department - Contracts

To Consumers:

Consumers Energy Company

1945 W. Parnall Road

Jackson, Michigan 49201

Attn: Director of Staff - Generation

To Transmission Provider:

Midcontinent Independent System Operator, Inc.

Attn: Manager, Interconnection Planning

701 City Center Drive

Carmel, IN 46032

20.2The Parties shall use standard telephone circuits as the primary communication link for generation dispatch communications, including with respect to dispatching energy in the event of an Emergency and declaring unit capability. The Parties shall provide the names and telephone numbers of appropriate contact personnel, as are set forth in this Agreement or otherwise, to each other after this Agreement is executed and shall keep said listing of names and telephone numbers up to date.

ARTICLE 21

MISCELLANEOUS

21.1Amendments

This Agreement may be amended by and only by a written instrument duly executed by the Parties hereto. No change or modification as to any of the provisions hereof shall be binding on any Party unless approved in writing and approved by the duly authorized officers of the Parties. Notwithstanding the foregoing, nothing contained herein shall be construed as affecting in any way the right of Transmission Provider, Transmission Owner or Consumers to unilaterally make application to the Commission for a change in rates, terms or conditions of service under Sections 205 and 206 of the Federal Power Act and pursuant to the Commission's Rules and Regulations promulgated thereunder. Transmission Provider reserves the right to file rate schedules with the Commission concerning any services Transmission Provider deems necessary for reliable and orderly bulk power system management, including but not limited to any standby or related services that may arise from a failure by Consumers to meet its schedule of deliveries across the assets covered by this Agreement.

21.2Binding Effect

This Agreement and the rights and obligations hereof, shall be binding upon and shall inure to the benefit of the successors and assigns of the Parties hereto.

21.3Counterparts

This Agreement may be executed in any number of counterparts, and each executed counterpart shall have the same force and effect as an original instrument.

21.4Entire Agreement

This Agreement constitutes the entire agreement among the Parties hereto with reference to the subject matter hereof and its execution superseded all previous agreements, discussions, communications and correspondence with respect to said subject matter. The terms and conditions of this Agreement and every Exhibit referred to herein shall be amended, as mutually agreed to by the Parties, to comply with changes or alterations made necessary by a valid applicable order of any governmental regulatory authority, or any court, having jurisdiction hereof.

21.5Governing Law

The validity, interpretation and performance of this Agreement and each of its provisions shall be governed by the applicable laws of the State of Michigan, exclusive of its conflict of laws principles.

21.6Headings Not To Affect Meaning

The descriptive headings of the various Articles and Sections of this Agreement have been inserted for convenience of reference only and shall in no way modify or restrict any of the terms and provisions hereof.

21.7Waivers

Any waiver at any time by a Party of its rights with respect to a default under this Agreement, or with respect to any other matters arising in connection with this Agreement, shall not be deemed a waiver or continuing waiver with respect to any subsequent default or other matter.

21.8 Termination of Predecessor Interconnection Agreement

On the Effective Date, the September 18, 2012 Amendment and Restatement of the Generator Interconnection Agreement between Transmission Provider, Transmission Owner and Consumers effective December 1, 2012 shall terminate and be replaced by this Agreement with regard to the Units covered by this Agreement, except insofar as necessary to resolve billing and related matters arising from service rendered and other events occurring before the Effective Date.

IN WITNESS WHEREOF, the Parties hereto have caused this Agreement to be duly executed by their duly authorized officers.

MICHIGAN ELECTRIC TRANSMISSION COMPANY, LLC, a Michigan limited liability company

By: ITC Holdings Corp., its manager

By _/s/ Gregory Ioanidis__________________

Title_Vice President_______________________

CONSUMERS ENERGY COMPANY

By _/s/ David B. Kehoe______________________

Title Director of Staff - Electric Generation_______

MIDCONTINENT INDEPENDENT SYSTEM OPERATOR, INC.

By: _/s/ William C. Phillips_

Title: Vice President, Reliability & Security Relations

		Summer	Winter			Cooling
	Nameplate	Net	Net			Hydrogen		AGC	Black
	Rated	Demonstrated	Demonstrated			Water/Hydrogen	AGC	Ramp	Start	Synch
Generating Unit	MVA (1)	MW Capability	MW Capability	Kilovolts	RPM	Air	Capable	MW/Min	Capable	Breaker(s)	Comments
Campbell 1	312	260	260	16	3,600	Hydrogen	Yes	3	No	199
Campbell 2	492	355	360	20	3,600	Hydrogen	Yes	3	No	299
Campbell A	21.9	13	17	13.8	3,600	Hydrogen	No	—	No	C16	Mothballed until February 2015.
Cobb 1	81.2	61	61	14.4	3,600	Hydrogen	No	—	No	199	Mothballed until April 2013.
Cobb 2	81.2	61	61	14.4	3,600	Hydrogen	No	—	No	299	. Mothballed until April 2013.
Cobb 3	81.2	61	61	14.4	3,600	Air	No	—	No	399	Mothballed until April 2013.
Cobb 4	184	158	160	18	3,600	Air	Yes	1	No	499
Cobb 5	184	158	160	18	3,600	Air	Yes	1	No	599
Gaylord 1	18.8	14	17	13.8	3,600	Air	No	—	No	116
Gaylord 2	18.8	14	17	13.8	3,600	Air	No	—	No	216
Gaylord 3	18.8	14	17	13.8	3,600	Hydrogen	No	—	No	316
Gaylord 4	18.8	14	17	13.8	3,600	Hydrogen	No	—	No	416	Extended maintenance outage. Return to service December 2012.
Gaylord 5	21.9	14	17	13.8	3,600	Water/Hydrogen	No	—	No	516	Retired on 10/15/2011
Karn 1	336	255	255	16	3,600	Water/Hydrogen	Yes	3	No	199
Karn 2	320	260	260	16	3,600	Air	Yes	3	No	299
Karn 3	814.7	638	638	26	3,600	Air	Yes	6	No	28R8/28H9	AGC Ramp Rate: 6 is avg. 9 Mw/min 60 thr. 500 Mw, 3 Mw/min 500 thr. 580 Mw
Karn 4	835	638	638	26	3,600	Air	Yes	6	No	32F7/32H9	AGC Ramp Rate: 6 is avg. 9 Mw/min 70 thr. 500 Mw, 3 Mw/min 500 thr. 580 Mw
Morrow A	20.7	14	17	13.8	3,600	Air	No	—	No	A16	Mothballed until February 2015.
Morrow B	20.7	14	17	13.8	3,600	Air	No	—	No	B16	Mothballed until February 2015.
Straits 1	25	16	21	13.8	3,600	Air	No	—	No	S16
Thetford 1	39.5	30	37	13.8	3,600	Air	No	—	No	116	Mothballed until October 2013.
Thetford 2	39.5	29	37	13.8	3,600	Air	No	—	No	216	Mothballed until October 2013.
Thetford 3	39.5	30	37	13.8	3,600	Air	No	—	Yes	316	Mothballed until May 2015.
Thetford 4	39.5	30	37	13.8	3,600	Air	No	—	Yes	416	Mothballed until May 2015.
Thetford 5	20.7	15	17	13.8	3,600	Air	No	—	No	516	Mothballed until October 2013.
Thetford 6	20.7	15	17	13.8	3,600	Air	No	—	No	616	Mothballed until October 2013.
Thetford 7	20.7	14	17	13.8	3,600	Hydrogen	No	—	No	716	Mothballed until October 2013.
Thetford 8	20.7	15	18	13.8	3,600	Hydrogen	No	—	Yes	816	Mothballed until May 2015.
Thetford 9	20.7	14	17	13.8	3,600	Air	No	—	Yes	916	Mothballed until May 2015.
Weadock 7	202	155	155	18	3,600	Hydrogen	Yes	1	No	799
Weadock 8	184	155	155	18	3,600	Hydrogen	Yes	1	No	899
Weadock A	21.9	13	17	13.8	3,600	Hydrogen	No	—	No	A16	Mothballed until October 2013.
Whiting 1	125	102	102	14.4	3,600	Air	Yes	1	No	199
Whiting 2	125	102	102	14.4	3,600	Air	Yes	1	No	299
Whiting 3	156.3	122	124	15.5	3,600	Air	Yes	1	No	399
Whiting A	21.9	13	17	13.8	3,600	Air	No	—	No	46A	Mothballed until October 2013.
Alcona Hydro 1	4.4	4	4	5	90	Air	NA	NA	No	116/166
Alcona Hydro 2	4.4	4	4	5	90	Air	NA	NA	No	216/166
Calkins Bridge Hydro 1	0.6	0.4	0.4	4.8	180	Air	NA	NA	No	116/166	Also known as Allegan Hydro
Calkins Bridge Hydro 2	1.1	0.9	0.9	4.8	120	Air	NA	NA	No	216/166	Also known as Allegan Hydro
Calkins Bridge Hydro 3	1.5	1.2	1.2	4.8	113	Air	NA	NA	No	316/166	Also known as Allegan Hydro
Cooke Hydro 1	3.3	1.5	1.5	2.5	180	Air	NA	NA	No	116/166
Cooke Hydro 2	3.3	3	3	2.5	180	Air	NA	NA	No	216/166
Cooke Hydro 3	3.3	3	3	2.5	180	Air	NA	NA	No	316/166
Croton Hydro 1	3.8	2.9	2.9	7.2	225	Air	NA	NA	No	116/246
Croton Hydro 2	3.8	2.9	2.9	7.2	225	Air	NA	NA	No	216/246
Croton Hydro 3	1.4	1.3	1.3	7.2	150	Air	NA	NA	No	316/246

Croton Hydro 4	1.6	1.3	1.3	7.2	150	Air	NA	NA	No	416/246
Five Channels 1	3.3	3.2	3.2	2.5	150	Air	NA	NA	No	116/166
Five Channels 2	3.3	3.2	3.2	2.5	150	Air	NA	NA	No	216/166
Foote Hydro 1	3.3	3.3	3.3	5	90	Air	NA	NA	No	116/366
Foote Hydro 2	3.3	3.3	3.3	5	90	Air	NA	NA	No	216/366
Foote Hydro 3	3.3	3.3	3.3	5	90	Air	NA	NA	No	316/366
Hodenpyl Hydro 1	8.9	9.2	9.2	7.5	120	Air	NA	NA	No	116/266
Hodenpyl Hydro 2	8.9	9.2	9.2	7.5	120	Air	NA	NA	No	216/266
Loud Hydro 1	2.2	2.2	2.2	2.5	120	Air	NA	NA	No	116/266
Loud Hydro 2	2.2	2.2	2.2	2.5	120	Air	NA	NA	No	216/266
Mio Hydro 1	2.7	2.2	2.2	2.5	80	Air	NA	NA	No	116/166
Mio Hydro 2	2.7	2.2	2.2	2.5	80	Air	NA	NA	No	216/166
Rogers Hydro 1	1.9	1.5	1.5	7.5	150	Air	NA	NA	No	116/166
Rogers Hydro 2	1.9	1.5	1.5	7.5	150	Air	NA	NA	No	216/166
Rogers Hydro 3	1.9	1.5	1.5	7.5	150	Air	NA	NA	No	316/166
Rogers Hydro 4	1.9	1.5	1.5	7.5	150	Air	NA	NA	No	416/166
Tippy Hydro 1	7.1	7	7	7.5	109	Air	NA	NA	No	116/266/126
Tippy Hydro 2	7.1	7	7	7.5	109	Air	NA	NA	No	216/266/126
Tippy Hydro 3	7.1	7	7	7.5	109		NA	NA	No	316/266/126
Webber Hydro 1	3.3	2.3	2.3	7.2	164		NA	NA	No	116/166
Webber Hydro 2	1.3	1	1	2.5	200		NA	NA	No	216
Notes:
(1) Rated MVA represents generator machine capability limits. Turbine or main transformer limits may be more restrictive.

EXHIBIT B - INTERCONNECTION ASSETS

General

The Parties agree that certain assets located at each of the electrical Substations at which Consumers’ Generation Resources are connected to the Transmission System are an integral part of the assets required by the Parties to provide services under their respective charters and that the physical partition would be impossible, impractical and wholly inconsistent with the purposes for which this Agreement is made. Said assets are deemed to be Jointly Owned Assets. In general, said assets include, but in some of the electrical Substations shall not be limited to, the following:

Foundations All foundations not identified as belonging to a specific piece of assets in the Plant Accounting Records.

Structures All steel support structures.

Station wiring All buswork, control cables, batteries, battery chargers and ground grids.

Fencing All chain-link fencing surrounding or used within the specific electrical Substation.

Control house Any building located within the Substation used to house relaying, controls or telemetry equipment beneficial to and used by both Parties.

Stone All stone used in the Substation yards, driveways and drains.

At each of the substations listed in this Exhibit B, an allocated percentage of the Jointly Owned Assets is determined for each Party hereto, in accordance with the provisions of this Agreement

For each of the electrical Substations at which Consumers’ Generation Resources are connected to the Transmission System, the specific assets allocated to and owned by Consumers are identified below as Consumers’ Interconnection Assets. In certain 345 kV

Substations, specific breakers and associated assets that have been designated for operation by Consumers are also specifically identified as Transmission Owner’s Interconnection Assets.

Some of the electrical Substations containing Interconnection Assets also contain Distribution System assets owned by Consumers. Unless said Distribution System assets are directly involved in the connection of Consumers’ Generation Resources to the Transmission System, they are not described in the description of assets that follow.

The balance of the assets in each electrical Substation are allocated to and owned by the Transmission Owner and considered a part of the Transmission System.

Wiring Diagrams (WDs) will be updated continuously in each Party’s Drawing Management System (DMS) which is shared between the Parties and approved in writing by the Local Distribution Company to show changes in ownership. For current ownership (reflecting ownership changes since July 24, 2008), see the WDs in the DMS.

Exhibit B - Table 1

Jointly Owned Asset Ownership by Percent of Major Equipment

Addendum 3 - Final 008/16/12

Substations

Jointly Owned Assets

Percentage Split by Major Equipment Count

(Substations with 100% ownership by Major Equipment Count Not Included)

Substation Name	Distribution	Transmission	Generation Owned by Local Distribution Company	Third-Party Assets	Last Revision Date
Campbell 138 kV 1	0.00	64.28	35.24	0.48	08/16/12
Cobb Plant	47.22	25.00	27.78		04/29/02
Gaylord	44.44	44.44	11.12		01/01/10
Karn Plant	0.00	63.64	36.36		01/01/10
Morrow	63.33	30.00	6.67		08/16/12
Thetford	0.00	92.00	8.00		04/29/02
Weadock	35.14	24.32	40.54		01/01/10
Whiting	28.57	28.57	42.86		08/16/12

_______________________

¹ At 120 kV and above, third-party related assets will be included as part of the Transmission assets for purposes of making this calculation. Also, the third party may share in the financial responsibility associated with O&M activities.

Changes, relative to previous revisions (addendums), are shown in bold type.

Major equipment is defined in Section 5.4 of the GIA.Generator Connections located at

Substations in the Transmission System

Campbell 1&2 Plant

The Campbell 1&2 Plant consists of three generating Units, known as Unit 1 (consisting of generators 1A and 1B), Unit 2 and Unit A. (The Campbell 3 Plant is located at the same site, but has separate interconnection facilities and is covered by a separate generator interconnection agreement.)

The Connection Point for Units 1, 2 and A are in the Campbell 138 kV Substation (see Wiring Diagram #93, Sheet 31 attached).

The Points of Receipt for all the Units in the Campbell 1&2 Plant are deemed to be the respective Connection Points.

Consumers’ Interconnection Assets

Consumers’ owns the following assets at the Campbell 138 kV Substation (Wiring Diagram #93, Sheet 31):

Transformer BankNo. A (located outside of substation; not included in JOA calc)

Circuit Breakers Nos. 199, 299, 799, 899*, 999 and 16A (16A is rated < 23kV and not considered major equipment per GIA definition).

Switches Nos. 99A, 195, 196, 295, 296, 709, 793, 795, 796, 809*, 893*, 895*, 896*, 909, 993, 995 and 996

Circuit Connections All wire, cable or buswork electrically connecting the switches identified above to the Circuit Breakers identified above and to the main or transfer buswork

Relay & Controls All relays and controls associated with the Circuit Breakers identified above

FoundationsAll foundations supporting the Circuit Breakers identified above

* Jointly Owned asset with Michigan Public Power Agency (4.8%) and Wolverine Power Supply Cooperative (1.8%)

Transmission Owner Interconnection Assets

Transmission Owner owns the following assets at the Campbell 138 kV Substation (Wiring Diagram #93, Sheet 31):

Transformer BankNo. 5

Circuit BreakersNos. 148, 188, 288, 388, 488, 500, 566 and 588

Switches Nos. 108, 144, 145, 146, 184, 185, 186, 208, 284, 285, 286, 308, 384, 385, 386, 408, 484, 485, 486, 505, 506, 508, 509, 545, 546, 564, 584, 585, 586, 1020 and 1121

Circuit Connections All wire, cable or bus work electrically connecting the switches identified above to the Circuit Breakers identified above and to the main or transfer bus work

Relay and Controls All relays and controls associated with the Circuit Breakers identified above

Foundations All foundations supporting the Circuit Breakers identified above

Jointly Owned Assets - Percentage Split by Major Equipment Count

Campbell 138 kV Substation - See Exhibit B - Table 1

CEII MATERIAL

Cobb Generating Plant Complex

The Cobb Generating Plant Complex consists of five generating Units, known as Units 1 through 5, respectively.

The Connection Points for Units 1 through 5 are in the BC Cobb Plant Substation (see Wiring Diagram #240, Sheet 31 attached).

The Points of Receipt for all the Units in the Cobb Generating Plant Complex are deemed to be the respective Connection Points.

Consumers’ Interconnection Assets

Consumers owns the following assets at the BC Cobb Plant Substation (Wiring Diagram #240, Sheet 31):

Transformer BanksNos. 1, 2, 3, 4, 5, 7 and 8

Capacitor Banks Nos. 1 and 2

Circuit Breakers Nos. 100, 188, 199, 288, 299, 399, 499, 599, 766, 799, 866, 899, 1177, 1188, 1288, 1388, 1488 and 1688

Switches Nos. 102, 104, 152, 156, 184, 185, 186, 193, 195, 196, 200, 252, 256, 284, 285, 286, 293, 295, 296, 393, 395, 396, 493, 495, 496, 593, 595, and 596, 709, 762, 764, 765, 793, 795, 796, 809, 862, 864, 865, 893, 895, 896, 1171, 1173, 1175, 1182, 1184, 1185, 1282, 1284, 1285, 1323, 1382, 1384, 1385, 1482, 1484, 1485, 1588, 1682, 1684, 1685, 1788, 1888, 2333, 7732-1, 7736-1, 8826-2, 8832-2 and 8836-2

Circuit Connections All wire, cable or buswork electrically connecting the switches identified above to the Circuit Breakers identified above and to the main buswork.

Relay & Controls All relays and controls associated with the Circuit Breakers identified above

Foundations All foundations supporting the Transformers and Circuit Breakers identified above

Auxiliary Power All 2400 Volt station power assets shown in the attached Wiring Diagram #240

Transmission Owner Interconnection Assets

Transmission Owner owns the following assets at the BC Cobb Plant Substation (Wiring Diagram #240, Sheet 31):

Circuit Breakers Nos. 148, 377, 488, 500, 588, 688, 788, 888 and 988

Switches Nos. 144, 145, 146, 307, 373, 375, 376, 408, 484, 485, 486, 505, 506, 508, 584, 585, 586, 608, 684, 685, 686, 708, 784, 785, 786, 808, 884, 885, 886,

908, 984, 985, 986, 1020, 1121, 2030 and 2131

Circuit Connections All wire, cable or buswork electrically connecting the switches identified above to the Circuit Breakers identified above and to the main buswork.

Relay & Controls All relays and controls associated with the Circuit Breakers identified above

Foundations All foundations supporting the Circuit Breakers identified above

Jointly Owned Assets - Percentage Split by Major Equipment Count

Cobb Plant Substation -See Exhibit B - Table 1

CEII MATERIALGaylord Generating Plant Complex

The Gaylord Generating Plant Complex consists of five combustion turbine generating Units, known as Units 1 through 5, respectively.

The Connection Points for Units 1 through 5 are in the Gaylord Generating Substation (see Wiring Diagram #495, Sheet 31 attached).

The Points of Receipt for all the Units in the Gaylord Generating Plant Complex are deemed to be the respective Connection Points.

Consumers’ Interconnection Assets

Consumers owns the following assets at the Gaylord Generating Substation (Wiring Diagram #495, Sheet 31):

Transformer BanksNos. 1, 2* and 3* (*located outside of substation; not included in JOA calc)

Circuit Breakers Nos. A16*, 116*, 146, 166, 199, 216*, 316*, 416* and 1288 (*located outside of substation; not included in JOA calc)

Switches Nos. 3,142, 144, 145, 162, 164, 165, 191, 193, 195, 299, 399, 1282 and 1284

Circuit Connections All wire, cable or buswork electrically connecting the switches identified above to the Circuit Breakers identified above

Relay & Controls All relays and controls associated with the Circuit Breakers identified above

Foundations All foundations supporting the Transformers and Circuit Breakers identified above

Auxiliary Power All station power assets shown in the attached Wiring Diagram #495, Sheet 31

Transmission Owner Interconnection Assets

Transmission Owner owns the following assets at the Gaylord Generating Substation (Wiring Diagram #495, Sheet 31):

Capacitor Bank No. 3

Circuit Breakers Nos. 356, 377 and 477

Switches Nos. 352, 371, 373, 375. 382, 384, 385, 471, 473, 475, 671, 673 and 675

Circuit Connections All wire, cable or buswork electrically connecting the switches identified above to the Circuit Breakers identified above

Relay & Controls All relays and controls associated with the Circuit Breakers identified above

Foundations All foundations supporting the Circuit Breakers identified above

Jointly Owned Assets - Percentage Split by Major Equipment Count

Gaylord Generating Substation - See Exhibit B - Table 1

CEII MATERIAL

Karn Generating Plant Complex

The Karn Generating Plant Complex consists of four generating Units, known as Units 1 (consisting of generators 1A and 1B), Unit 2 (consisting of generators 2A and 2B, Unit 3 and Unit 4.

The Connection Point for Units 1 and 2 are in the DE Karn Plant 138 kV Substation (see Wiring Diagram #695, Sheet 31 attached). The Connection Point for Units 3 and 4 are in the Hampton 345 kV Substation (see Wiring Diagram #1327, Sheet 31 attached).

The Points of Receipt for all the Units in the DE Karn Generating Plant Complex are deemed to be the respective Connection Points.

Consumers’ Interconnection Assets

Consumers owns the following assets at the DE Karn 138 kV Substation (Wiring Diagram #695, Sheet 31):

Transformer Banks Nos. 1 and 2 (located outside the substation; not included in JOA calc)

Circuit BreakersNos. 199, 299, 799 and 899

Switches Nos. 136A, 136B, 195, 196, 236A, 236B, 295, 296, 793, 795, 796, 893, 895, and 896

Circuit Connections All wire, cable or buswork electrically connecting the switches identified above to the Circuit Breakers identified above and to the main or transfer buswork

Relay & Controls All relays and controls associated with the Circuit Breakers identified above

FoundationsAll foundations supporting the Circuit Breakers identified above

Auxiliary Power All 480 Volt and 4160 Volt station power assets shown in the attached Wiring Diagram #695, Sheet 31

Transmission Owner’s Interconnection Assets

Transmission Owner owns the following assets at the DE Karn 138 kV Substation (Wiring Diagram #695, Sheet 31):

Circuit BreakersNos. 148, 188, 388, 488, 500, 588 and 988

Switches Nos. 108, 144, 145, 146, 184, 185, 186, 308, 384, 385, 386, 408, 484, 485, 486, 505, 506, 508, 584, 585, 586, 709, 809, 908, 984, 985, 986, 2030 and 2131

Circuit Connections All wire, cable or buswork electrically connecting the switches identified above to the Circuit Breakers identified above and to adjacent buswork

Relay & Controls All relays and controls associated with the Circuit Breakers identified above

FoundationsAll foundations supporting the Circuit Breakers identified above

Jointly Owned Assets - Percentage Split by Major Equipment Count

Karn Plant Substation - See Exhibit B - Table 1

CEII MATERIAL

CEII MATERIAL

Morrow Generating Plant Complex

The Morrow Generating Plant Complex consists of two combustion turbine generating Units, known as Units A and B.

The Connection Points for both Units A and B are in the Morrow Substation (see Wiring Diagram #190, Sheet 31, attached).

The Points of Receipt for the Units in the Morrow Generating Plant Complex are deemed to be the Connection Points.

Consumers’ Interconnection Assets

Consumers’ owns the following assets at the Morrow Substation (Wiring Diagram #190, Sheet 31):

Transformer Banks No. 1, 2, 4 and 5

Circuit Breakers Nos. 100, 156, 166, 199, 256, 266, 299, 566, 499, 16A,16B, 599, 1077, 1188, 1388, 1488, 1588, 1688 and 1788

Switches Nos. 102, 104, 109, 162, 164, 165, 191, 193, 195, 196, 209, 252, 262, 264, 265, 291, 293, 295, 296, 300, 495, 496, 509, 562, 564, 565, 591, 593, 595, 596, 1071, 1073, 1075, 1182, 1184, 1185, 1323, 1382, 1384, 1385, 1482, 1484, 1485, 1582, 1584, 1585, 1682, 1684, 1685, 1782, 1784, 1785 and 2333

CapacitorsNos. 1 and 2

Circuit Connections All wire, cable or buswork electrically connecting the Transformers, Circuit Breakers and Switches identified above

Relay & Controls All relays and controls associated with the Circuit Breakers identified above

Foundations All foundations supporting the Transformers and Circuit Breakers identified above

Auxiliary Power All 480 Volt station power assets shown in the attached Wiring Diagram #190, Sheet 31

Transmission Owner Interconnection Assets

Transmission Owner owns the following assets at the Morrow Substation (Wiring Diagram #190, Sheet 31):

Circuit BreakersNos. 177, 288, 377, 388, 500, 588, 677, 888 and 988

Switches Nos. 107, 171, 173, 175, 176, 208, 282, 284, 285, 286, 307, 308, 371, 373, 375, 376, 382, 384, 385, 386, 501, 502, 503, 504, 505, 506, 508, 582, 584, 585, 586, 607, 671, 673, 675, 676, 882, 884, 885, 886, 908, 982, 984, 985 and 986

Circuit Connections All wire, cable or buswork electrically connecting the Circuit Breakers and Switches identified above

Relay and Controls All relays and controls associated with the Circuit Breakers identified above

Foundations All foundations supporting the Circuit Breakers identified above

Third Party Owned Assets

None

Jointly Owned Assets - Percentage Split by Major Equipment Count

Morrow Substation - See Exhibit B - Table 1

CEII MATERIAL

Thetford Generating Plant Complex

The Thetford Generating Plant Complex consists of nine combustion turbine generating Units, known as Units 1 through 9, respectively.

The Connection Points for Units 1 through 9 are in the Thetford Substation (see Wiring Diagram #1000, Sheet 31 attached).

The Points of Receipt for all the Thetford Units are deemed to be the respective Connection Points.

Consumers’ Interconnection Assets

Consumers owns the following assets at the Thetford Substation (Wiring Diagram #1000, Sheet 31):

Transformer Banks Nos. 5, 6-1, 6-2 and 7

Circuit BreakersNos. 13B7, 13W8, 116, 216, 316, 416, 516, 616, 716, 816 and 916

SwitchesNos. 13B1, 13B3, 13M5, 13W2, 13W4, 591, 691-1, 691-2 and 791

Circuit Connections All wire, cable or buswork electrically connecting the Transformer Banks, Circuit Breakers and Switches identified above

Relay & Controls All relays and controls associated with the Circuit Breakers identified above

Foundations All foundations supporting the Transformers and Circuit Breakers identified above

Transmission Owner Interconnection Assets

Transmission Owner owns the following assets at the Thetford Substation (Wiring Diagram #1000, Sheet #31):

Transformer Banks Nos. 3 and 4

Circuit Breakers Nos. 6B7, 6M9, 6W8, 7B7, 7M9, 7W8, 9B7, 9M9, 9W8, 11B7, 11M9, 11W8, 27F7, 27H9, 27R8, 31F7, 31H9, 31R8, 33F7, 33H9 and 33R8

Switches Nos. 6B1, 6B3, 6M5, 6M6, 6W2, 6W4, 7B1, 7B3, 7M5, 7M6, 7W2, 7W4, 9B1, 9B3, 9M5, 9M6, 9W2, 9W4, 11B1, 11B3, 11M5, 11M6, 11W2, 399, 499, 11W4, 27F1, 27F3, 27H5, 27H6, 27R2, 27R4, 31F1, 31F3, 31H5, 31H6, 31R2, 31R4, 33F1, 33F3, 33H5, 33H6, 33R2, 33R4 and 35R2

Circuit Connections All wire, cable or buswork electrically connecting the Transformer Banks, Circuit Breakers and Switches identified above

Relay and Controls All relays and controls associated with the Circuit Breakers identified above

Foundations All foundations supporting the Transformers and Circuit Breakers identified above

Jointly Owned Assets - Percentage Split by Major Equipment Count

Thetford Substation - See Exhibit B - Table 1

CEII MATERIAL

Weadock Generating Plant Complex

The Weadock Generating Plant Complex consists of three generating Units, known as Units 7, 8 and A.

The Connection Points for Units 7, 8 and A1 are in the John C Weadock Substation (see Wiring Diagram #195, Sheet 31 attached). These Units are currently in service. In addition, there are six other units, known as Units 1 through 6, which have been retired from service, but are still in place. Those assets are also described below, should the Units be restored to service in the future.

The Points of Receipt for all the Units currently in service at the Weadock Generating Plant Complex are deemed to be the respective Connection Points.

Consumers’ Interconnection Assets (for Units In Service)

Consumers owns the following assets at the John C Weadock Substation (Wiring Diagram #195, Sheets 2 and 31):

Transformer Banks Nos. 1, 2, 7, 8, 9 and 10

Circuit Breakers Nos. 66A, 100, 136, 166, 199, 236, 266, 299, 300, 736C, 799, 899, 966, 999, 1066, 1088, 1099, 1188, 1288 and 1388

Switches Nos. 62A, 64A, 102, 104, 105, 106, 132, 134, 135, 152, 156, 162, 164, 165, 195, 196, 200, 232, 234, 235, 252, 256, 262, 264, 265, 295, 296, 302, 304, 306, 400, 732C, 734C, 735C, 736A, 736B, 795, 796, 836A, 836B, 895, 896, 962, 964, 965, 991, 993, 995, 996, 1062, 1064, 1065, 1082, 1084, 1085, 1091, 1093, 1095, 1096, 1182, 1184, 1185, 1282, 1284, 1285, 1382, 1384 and 1385

Capacitors1 and 2

Circuit Connections All wire, cable or buswork electrically connecting the Switches identified above to the Circuit Breakers identified above and to the main buswork.

Relay & Controls All relays and controls associated with the Circuit Breakers identified above

Foundations All foundations supporting the Transformer Banks and Circuit Breakers identified above

Auxiliary Power All 480 Volt and 4160 Volt station power assets shown in the attached Wiring Diagram #195, Sheet 31

Consumers’ Interconnection Assets (for Units Retired in Place)

Consumers owns the following assets at the John C Weadock Substation (Wiring Diagram

#195, Sheet 31):

Transformer BanksNos. 5 and 6

Circuit BreakersNos. 99A, 116, 216, 316, 336, 416 and 436

Switches Nos. 93A, 112, 114, 212, 214, 312, 314, 332, 412, 414, 432, 516, 536 and 616

Circuit Connections All wire, cable or buswork electrically connecting the Switches identified above to the Circuit Breakers identified above and to the main buswork.

Relay & Controls All relays and controls associated with the Circuit Breakers identified above

Foundations All foundations supporting the Transformer Banks and Circuit Breakers identified above

Transmission Owner Interconnection Assets

Transmission Owner owns the following assets at the John C Weadock Substation (Wiring Diagram #195, Sheet 31):

Circuit BreakersNos. 148, 188, 288, 388, 488, 500, 588, 688 and 788

Switches Nos. 108, 142, 144, 145, 146, 182, 184, 185, 186, 208, 282, 284, 285, 286, 308, 382, 284, 385, 386, 408, 482, 484, 485, 486, 505, 506, 508, 582, 584, 585, 586, 608, 682, 684, 685, 686, 708, 782, 784, 785, 786, 900, 1020,1121, 2030, 2131, 3040, 3141, 4050 and 4151

Circuit Connections All wire, cable or buswork electrically connecting the Switches identified above to the Circuit Breakers identified above and to the main buswork

Relay & Controls All relays and controls associated with the Circuit Breakers identified above

Foundations All foundations supporting the Circuit Breakers identified above

Jointly Owned Assets - Percentage Split by Major Equipment Count

John C Weadock Substation - See Exhibit B - Table 1

CEII MATERIAL

Whiting Generating Plant Complex

The Whiting Generating Plant Complex consists of four generating Units, known as Units 1, 2, 3 and A.

The Connection Points for Units 1, 2, 3 and A are in the Whiting Substation (see Wiring Diagram #400, Sheet 31attached). Units 1, 2 and 3 are connected to the 138 Kv buswork and Unit A is connected to the 46 Kv buswork

The Points of Receipt for all the Units in the Whiting Generating Plant Complex are deemed to be the respective Connection Points.

Consumers’ Interconnection Assets

Consumers owns the following assets at the Whiting Substation (Wiring Diagram #400, Sheet 31):

Transformer Banks Nos. 1, 2, 3, 5, 7 and A (TB # A located outside of substation; not included in

JOA calc)

Circuit Breakers Nos. 16A (located outside switchyard; not included in JOA calc), 46A, 199, 299, 399, 599, 766, 799, 1188 and 1288

Switches Nos. 42A, 44A, 45A, 99A, 105, 156, 191, 193, 195, 196, 291, 293, 295, 296, 391, 393, 395, 396, 591, 593, 79T1, 762, 764, 765, 795, 796, 1182, 1184, 1185, 1282, 1284, 1285

Capacitor Bank No 1

Circuit Connections All wire, cable or buswork electrically connecting the Transformer Banks, Circuit Breakers and Switches identified above to each other, as appropriate, to the main buswork and to the Auxiliary Power assets

Relay & Controls All relays and controls associated with the Circuit Breakers identified above

Foundations All foundations supporting the Transformer Banks and Circuit Breakers identified above

Auxiliary Power All 480 Volt and 2400 Volt station power assets shown in the attached Wiring Diagram #400, Sheet 31

Transmission Owner Interconnection Assets

Transmission Owner owns the following assets at the Whiting Substation (Wiring Diagram #400, Sheet 31):

Transformer Bank No. 8

Circuit BreakersNos. 500, 688, 788,899 and 988

Switches Nos. 501, 502, 503, 504, 505, 506, 608, 682, 684, 685, 686, 785, 786, 866, 895, 896, 908, 982, 984, 985 and 986

Circuit Connections All wire, cable or buswork electrically connecting the Transformer Banks, Circuit Breakers and Switches identified above to each other, as appropriate, to the main buswork

Relay & Controls All relays and controls associated with the Circuit Breakers identified above

Foundations All foundations supporting the Transformer Bank and Circuit Breakers identified above

Jointly Owned Assets - Percentage Split by Major Equipment Count

Whiting Substation - See Exhibit B - Table 1

CEII MATERIAL

EXHIBIT C

Generator Connections located in Consumers’ Distribution System

The following Units are connected indirectly to the Transmission System and do not have specific connection data listed herein.

Alcona Hydro Generating Plant, Units 1 and 2

Calkins Bridge “Allegan” Hydro Generating Plant, Units 1, 2 and 3

Cooke Hydro Generating Plant, Units 1. 2 and 3

Croton Hydro Generating Plant, Units 1, 2, 3 and 4

Five Channels Generating Plant, Units 1 and 2

Foote Hydro Generating Plant, Units 1, 2 and 3

Hodenpyl Hydro Generating Plant, Units 1 and 2

Loud Hydro Generating Plant, Units 1 and 2

Mio Hydro Generating Plant, Units 1 and 2

Rogers Hydro Generating Plant, Units 1, 2, 3 and 4

Straits Combustion Turbine Generating Unit 1

Tippy Hydro Generating Plant, Units 1, 2 and 3

Webber Hydro Generating Plant, Units 1 and 2

Consumers Energy Generator Connections Covered under Other Interconnection Agreements

The following Units are covered under their own GIAs and do not have specific connection data listed herein.

Campbell Generating Plant, Unit 3.

Hardy Hydro Generating Plant, Units 1, 2 and 3.

Zeeland Power Plant

Ludington Units 1,2,3,4,5 and 6.

EX-10.125

Original Sheet No. 1

Exhibit 10.125

AMENDED AND RESTATED

LARGE GENERATOR INTERCONNECTION AGREEMENT

entered into by

Midcontinent Independent System Operator, Inc.

and

Interstate Power and Light Company

and

ITC Midwest LLC

on this6^th day of August, 2013

LARGE GENERATOR INTERCONNECTION

AGREEMENT (LGIA)

(Applicable to Generating Facilities that exceed 20 MW)

THIS AMENDED and RESTATED LARGE GENERATOR INTERCONNECTION AGREEMENT (“LGIA”) is made and entered into this6th day of August, 2013, by and between Interstate Power and Light Company, a corporation organized and existing under the laws of the State of Iowa (“Interconnection Customer” with Large Generating Facilities), and ITC Midwest LLC, a limited liability corporation organized and existing under the laws of the State of Michigan (“Transmission Owner”), and the Midcontinent Independent System Operator, Inc., a non-profit, non-stock corporation organized and existing under the laws of the State of Delaware (“Transmission Provider”). Interconnection Customer, Transmission Owner, and Transmission Provider each may be referred to as a “Party,” or collectively as the “Parties.”

RECITALS

WHEREAS, Transmission Provider operates and/or controls the Transmission System; and

WHEREAS, Interconnection Customer owns, leases, and/or controls and operates the Generating Facilities identified as Large Generating Facilities in Appendix A to this LGIA; and

WHEREAS, Transmission Owner owns or operates the Transmission System, whose operations are subject to the functional control of the Transmission Provider, to which the Interconnection Customer has connected the Large Generating Facilities, and may therefore be required to construct certain Interconnection Facilities and Network Upgrades, as set forth in this LGIA; and

Original Sheet No. 2

WHEREAS, Interconnection Customer, Transmission Owner, and Transmission Provider have agreed to enter into this LGIA for the purpose of upgrading and constructing facilities necessary for the interconnection and/or operation of the Large Generating Facilities with the Transmission System;

NOW, THEREFORE, in consideration of and subject to the mutual covenants contained herein, it is agreed:

ARTICLE 1. DEFINITIONS

When used in this LGIA, terms with initial capitalization that are not defined in Article 1 shall have the meanings specified in the Article in which they are used. Those capitalized terms used in this LGIA that are not otherwise defined in this LGIA have the meaning set forth in the Tariff.

Adverse System Impact shall mean the negative effects due to technical or operational limits on conductors or equipment being exceeded that may compromise the safety and reliability of the electric system.

Affected System shall mean an electric transmission or distribution system or the electric system associated with an existing generating facility or of a higher queued Generating Facility, which is an electric system other than the Transmission System that may be affected by the Interconnection Request. An Affected System may or may not be subject to FERC jurisdiction.

Affected System Operator shall mean the entity that operates an Affected System.

Affiliate shall mean, with respect to a corporation, partnership or other entity, each such other corporation, partnership, or other entity that directly or indirectly, through one or more intermediaries, controls, is controlled by, or is under common control with, such corporation, partnership, or other entity.

Ancillary Services shall mean those services that are necessary to support the transmission of capacity and energy from resources to loads while maintaining reliable operation of the Transmission System in accordance with Good Utility Practice.

Applicable Laws and Regulations shall mean all duly promulgated applicable federal, state, and local laws, regulations, rules, ordinances, codes, decrees, judgments, directives, or judicial or administrative orders, permits, and other duly authorized actions of any Governmental Authority having jurisdiction over the Parties, their respective facilities, and/or the respective services they provide.

Applicable Reliability Council shall mean the reliability council of NERC applicable to the Control Area of the Transmission System to which the Generating Facility is directly interconnected.

Applicable Reliability Standards shall mean the requirements and guidelines of NERC, the Applicable Reliability Council, and the Control Area of the Transmission System to which the Generating Facility is directly interconnected.

Original Sheet No. 3

Base Case shall mean the base case power flow, short circuit, and stability databases used for the Interconnection Studies by the Transmission Provider or Interconnection Customer.

Breach shall mean the failure of a Party to perform or observe any material term or condition of this LGIA.

Breaching Party shall mean a Party that is in Breach of this LGIA.

Business Day shall mean Monday through Friday, excluding Federal Holidays.

Calendar Day shall mean any day including Saturday, Sunday or a Federal Holiday.

Commercial Operation shall mean the status of a Generating Facility that has commenced generating electricity for sale, excluding electricity generated during Trial Operation.

Commercial Operation Date of a unit shall mean the date on which the Generating Facility commences Commercial Operation as agreed to by the Parties pursuant to Appendix E to this LGIA.

Confidential Information shall mean any proprietary or commercially or competitively sensitive information, trade secret, or information regarding a plan, specification, pattern, procedure, design, device, list, concept, policy, or compilation relating to the present or planned business of a Party, or any other information as specified in Article 22, which is designated as confidential by the Party supplying the information, whether conveyed orally, electronically, in writing, through inspection, or otherwise, that is received by another Party and is not disclosed except under the terms of a Confidential Information policy.

Control Area shall mean an electrical system or systems bounded by interconnection metering and telemetry, capable of controlling generation to maintain its interchange schedule with other Control Areas and contributing to frequency regulation of the interconnection. A Control Area must be certified by the Applicable Reliability Council.

Default shall mean the failure of a Breaching Party to cure its Breach in accordance with Article 17 of this LGIA.

Demonstrated Capability shall mean the continuous net real power output that the Generating Facility is required to demonstrate in compliance with Applicable Reliability Standards.

Dispute Resolution shall mean the procedure for resolution of a dispute between or among the Parties in which they will first attempt to resolve the dispute on an informal basis.

Distribution System shall mean the Transmission Owner’s facilities and equipment, or the Distribution System of another party that is interconnected with the Transmission Owner’s Transmission System, if any, connected to the Transmission System, over which facilities transmission service or Wholesale Distribution Service under the Tariff is available at the time the Interconnection Customer has requested interconnection of a Generating Facility for the purpose of either transmitting electric energy in interstate commerce or selling electric energy at wholesale in interstate commerce and which are used to transmit electricity to ultimate usage points such as homes and industries directly from nearby generators or from interchanges with

Original Sheet No. 4

higher voltage transmission networks which transport bulk power over longer distances. The voltage levels at which distribution systems operate differ among Control Areas and other entities owning distribution facilities interconnected to the Transmission System.

Distribution Upgrades shall mean the additions, modifications, and upgrades to the Distribution System at or beyond the Point of Interconnection to facilitate interconnection of the Generating Facility and render the delivery service necessary to effect Interconnection Customer’s wholesale sale of electricity in interstate commerce. Distribution Upgrades do not include Interconnection Facilities.

Effective Date shall mean the date on which this LGIA becomes effective upon execution by the Parties subject to acceptance by the Commission, or if filed unexecuted, upon the date specified by the Commission.

Emergency Condition shall mean a condition or situation: (1) that in the reasonable judgment of the Party making the claim is imminently likely to endanger, or is contributing to the endangerment of, life, property, or public health and safety; or (2) that, in the case of either Transmission Provider or Transmission Owner, is imminently likely (as determined in a non-discriminatory manner) to cause a material adverse effect on the security of, or damage to, the Transmission System, Transmission Owner’s Interconnection Facilities, or the electric systems of others to which the Transmission System is directly connected; or (3) that, in the case of Interconnection Customer, is imminently likely (as determined in a non-discriminatory manner) to cause a material adverse effect on the security of, or damage to, the Generating Facility or Interconnection Customer’s Interconnection Facilities. System restoration and blackstart shall be considered Emergency Conditions; provided that Interconnection Customer is not obligated by this LGIA to possess blackstart capability. Any condition or situation that results from lack of sufficient generating capacity to meet load requirements or that results solely from economic conditions shall not constitute an Emergency Condition, unless one of the enumerated conditions or situations identified in this definition also exists.

Energy Resource Interconnection Service (ER Interconnection Service) shall mean an Interconnection Service that allows the Interconnection Customer to connect its Generating Facility to the Transmission System or Distribution System, as applicable, to be eligible to deliver the Generating Facility’s electric output using the existing firm or non-firm capacity of the Transmission System on an as available basis. Energy Resource Interconnection Service does not convey transmission service.

Engineering & Procurement (E&P) Agreement shall mean an agreement that authorizes the Transmission Owner to begin engineering and procurement of long lead-time items necessary for the establishment of the interconnection in order to advance the implementation of the Interconnection Request.

Environmental Law shall mean Applicable Laws or Regulations relating to pollution or protection of the environment or natural resources.

Federal Holiday shall mean a Federal Reserve Bank holiday for a Party that has its principal place of business located in the United States, and a Canadian Federal or Provincial banking holiday for a Party that has its principal place of business located in Canada.

Original Sheet No. 5

Federal Power Act shall mean the Federal Power Act, as amended, 16 U.S.C. §§ 791a et seq.

FERC shall mean the Federal Energy Regulatory Commission, also known as Commission, or its successor.

Force Majeure shall mean any act of God, labor disturbance, act of the public enemy, war, insurrection, riot, fire, storm or flood, explosion, breakage or accident to machinery or equipment, any order, regulation, or restriction imposed by governmental, military, or lawfully established civilian authorities, or any other cause beyond a Party’s control. A Force Majeure event does not include an act of negligence or intentional wrongdoing by the Party claiming Force Majeure.

Generating Facility(ies) shall mean Interconnection Customer’s device(s) for the production of electricity identified in the Interconnection Request, but shall not include the Interconnection Customer’s Interconnection Facilities.

Generating Facility Capacity shall mean the net capacity of the Generating Facility and the aggregate net capacity of the Generating Facility where it includes multiple energy production devices.

Generator Upgrades shall mean the additions, modifications, and upgrades to the electric system of an existing generating facility or of a higher-queued Generating Facility at or beyond the Point of Interconnection to facilitate interconnection of the Generating Facility and render the transmission service necessary to affect Interconnection Customer’s wholesale sale of electricity in interstate commerce.

Good Utility Practice shall mean any of the practices, methods, and acts engaged in or approved by a significant portion of the electric industry during the relevant time period, or any of the practices, methods, and acts which, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety, and expedition. Good Utility Practice is not intended to be limited to the optimum practice, method, or act to the exclusion of all others, but rather to be acceptable practices, methods, or acts generally accepted in the region.

Governmental Authority shall mean any federal, state, local, or other governmental regulatory or administrative agency, court, commission, department, board, or other governmental subdivision, legislature, rulemaking board, tribunal, or other governmental authority having jurisdiction over the Parties, their respective facilities, or the respective services they provide, and exercising or entitled to exercise any administrative, executive, police, or taxing authority or power; provided, however, that such term does not include Interconnection Customer, Transmission Provider, Transmission Owner, or any Affiliate thereof.

Group Study(ies) shall mean the process whereby more than one Interconnection Request is studied together, instead of serially, for the purpose of conducting one or more of the required Studies.

Hazardous Substances shall mean any chemicals, materials, or substances defined as or included in the definition of “hazardous substances,” “hazardous wastes,” “hazardous

Original Sheet No. 6

materials,” “hazardous constituents,” “restricted hazardous materials,” “extremely hazardous substances,” “toxic substances,” “radioactive substances,” “contaminants,” “pollutants,” “toxic pollutants,” or words of similar meaning and regulatory effect under any applicable Environmental Law, or any other chemical, material, or substance, exposure to which is prohibited, limited, or regulated by any applicable Environmental Law.

Initial Synchronization Date shall mean the date upon which the Generating Facility is initially synchronized and upon which Trial Operation begins.

In-Service Date shall mean the date upon which the Interconnection Customer reasonably expects it will be ready to begin use of the Transmission Owner’s Interconnection Facilities to obtain backfeed power.

Interconnection Customer shall mean any entity, including the Transmission Provider, Transmission Owner, or any of the Affiliates or subsidiaries of either, that proposes to interconnect its Generating Facility with the Transmission System.

Interconnection Customer’s Interconnection Facilities shall mean all facilities and equipment, as identified in Appendix A of this LGIA, that are located between the Generating Facility and the Point of Change of Ownership, including any modification, addition, or upgrades to such facilities and equipment necessary to physically and electrically interconnect the Generating Facility to the Transmission System or Distribution System, as applicable. Interconnection Customer’s Interconnection Facilities are sole use facilities.

Interconnection Facilities shall mean the Transmission Owner’s Interconnection Facilities and the Interconnection Customer's Interconnection Facilities. Collectively, Interconnection Facilities include all facilities and equipment between the Generating Facility and the Point of Interconnection, including any modification, additions, or upgrades that are necessary to physically and electrically interconnect the Generating Facility to the Transmission System. Interconnection Facilities shall not include Distribution Upgrades, Generator Upgrades, Stand Alone Network Upgrades, or Network Upgrades.

Interconnection Facilities Study shall mean a study conducted by the Transmission Provider, or its agent, for the Interconnection Customer to determine a list of facilities (including Transmission Owner’s Interconnection Facilities, System Protection Facilities, and if such upgrades have been determined, Network Upgrades, Distribution Upgrades, Generator Upgrades, and upgrades on Affected Systems, as identified in the Interconnection System Impact Study), the cost of those facilities, and the time required to interconnect the Generating Facility with the Transmission System. The scope of the study is defined in Section 8 of the Large Generator Interconnection Procedures.

Interconnection Facilities Study Agreement shall mean the form of agreement contained in Appendix 4 of the Large Generator Interconnection Procedures for conducting the Interconnection Facilities Study.

Interconnection Feasibility Study shall mean a preliminary evaluation of the system impact of interconnecting the Generating Facility to the Transmission System, the scope of which is described in Section 6 of the Large Generator Interconnection Procedures.

Original Sheet No. 7

Interconnection Feasibility Study Agreement shall mean the form of agreement contained in Appendix 2 of the Large Generator Interconnection Procedures for conducting the Interconnection Feasibility Study.

Interconnection Request shall mean an Interconnection Customer’s request, in the form of Appendix 1 to the Large Generator Interconnection Procedures, to interconnect a new Generating Facility, or to increase the capacity of, or make a Material Modification to the operating characteristics of, an existing Generating Facility that is interconnected with the Transmission System.

Interconnection Service shall mean the service provided by the Transmission Provider associated with interconnecting the Generating Facility to the Transmission System and enabling it to receive electric energy and capacity from the Generating Facility at the Point of Interconnection, pursuant to the terms of this LGIA and, if applicable, the Tariff.

Interconnection Study shall mean any of the following studies: the Interconnection Feasibility Study, the Interconnection System Impact Study, and the Interconnection Facilities Study, or the Restudy of any of the above, described in the Large Generator Interconnection Procedures.

Interconnection System Impact Study shall mean an engineering study that evaluates the impact of the proposed interconnection on the safety and reliability of Transmission System and, if applicable, an Affected System. The study shall identify and detail the system impacts that would result if the Generating Facility were interconnected without project modifications or system modifications, focusing on the Adverse System Impacts identified in the Interconnection Feasibility Study, or to study potential impacts including, but not limited to, those identified in the Scoping Meeting as described in the Large Generator Interconnection Procedures.

Interconnection System Impact Study Agreement shall mean the form of agreement contained in Appendix 3 of the Large Generator Interconnection Procedures for conducting the Interconnection System Impact Study.

IRS shall mean the Internal Revenue Service.

Large Generating Facility(ies) shall mean a Generating Facility having an aggregate net Generating Facility Capacity of more than 20 MW.

Large Generator Interconnection Agreement (LGIA) shall mean the form of interconnection agreement, in the form of Appendix 6 to the Large Generator Interconnection Procedures, applicable to a Large Generating Facility.

Large Generator Interconnection Procedures (LGIP) shall mean the interconnection procedures that are included in the Tariff and applicable to an Interconnection Request pertaining to a Large Generating Facility.

Loss shall mean any and all damages, losses, claims, including claims and actions relating to injury to or death of any person or damage to property, demand, suits, recoveries, costs and expenses, court costs, attorney fees, and all other obligations by or to third parties arising out of or resulting from the other Party’s performance or non-performance of its

Original Sheet No. 8

obligations under this LGIA on behalf of the indemnifying Party, except in cases of gross negligence or intentional wrongdoing by the indemnified party.

Material Modification shall mean those modifications that have a material impact on the cost or timing of any Interconnection Request with a later queue priority date.

Metering Equipment shall mean all metering equipment installed or to be installed at the Generating Facility pursuant to this LGIA at the metering points, including but not limited to instrument transformers, MWh‑meters, data acquisition equipment, transducers, remote terminal unit, communications equipment, phone lines, and fiber optics.

NERC shall mean the North American Electric Reliability Council or its successor organization.

Network Customer shall have that meaning as provided in the Tariff.

Network Resource shall mean any designated generating resource owned, purchased, or leased by a Network Customer under the Network Integration Transmission Service Tariff. Network Resources do not include any resource, or any portion thereof, that is committed for sale to third parties or otherwise cannot be called upon to meet the Network Customer’s Network Load on a non‑interruptible basis.

Network Resource Interconnection Service (NR Interconnection Service) shall mean an Interconnection Service that allows the Interconnection Customer to integrate its Large Generating Facility with the Transmission System in the same manner as for any Large Generating Facility being designated as a Network Resource. Network Resource Interconnection Service does not convey transmission service.

Network Upgrades shall mean the additions, modifications, and upgrades to the Transmission System required at or beyond the point at which the Interconnection Facilities connect to the Transmission System or Distribution System, as applicable, to accommodate the interconnection of the Generating Facility to the Transmission System.

Notice of Dispute shall mean a written notice of a dispute or claim that arises out of or in connection with this LGIA or its performance.

Optional Interconnection Study shall mean a sensitivity analysis based on assumptions specified by the Interconnection Customer in the Optional Interconnection Study Agreement.

Optional Interconnection Study Agreement shall mean the form of agreement contained in Appendix 5 of the Large Generator Interconnection Procedures for conducting the Optional Interconnection Study.

Party or Parties shall mean Transmission Provider, Transmission Owner, Interconnection Customer, or any combination of the above.

Point of Change of Ownership shall mean the point, as set forth in Appendix A to the Large Generator Interconnection Agreement, where the Interconnection Customer’s Interconnection Facilities connect to the Transmission Owner’s Interconnection Facilities.

Point of Interconnection shall mean the point as set forth in Appendix A.

Original Sheet No. 9

Queue Position shall mean the order of a valid Interconnection Request, relative to all other pending valid Interconnection Requests, that is established based upon the date and time of receipt of the valid Interconnection Request by the Transmission Provider.

Reasonable Efforts shall have that meaning as provided in the Tariff.

Scoping Meeting shall mean the meeting between representatives of the Interconnection Customer, Transmission Owner, Affected System Operator(s), and Transmission Provider conducted for the purpose of discussing alternative interconnection options, to exchange information including any transmission data and earlier study evaluations that would be reasonably expected to impact such interconnection options, to analyze such information, and to determine the potential feasible Points of Interconnection.

Site Control shall mean documentation reasonably demonstrating: (1) ownership of, a leasehold interest in, or a right to develop a site for the purpose of constructing the Generating Facility; (2) an option to purchase or acquire a leasehold site for such purpose; or (3) an exclusivity or other business relationship between Interconnection Customer and the entity having the right to sell, lease, or grant Interconnection Customer the right to possess or occupy a site for such purpose.

Small Generating Facility(ies) shall mean a Generating Facility that has an aggregate net Generating Facility Capacity of no more than 20 MW.

Special Protection System (SPS) shall mean an automatic protection system or remedial action scheme designed to detect abnormal or predetermined system conditions, and take corrective actions other than, and/or in addition to, the isolation of faulted components, to maintain system reliability. Such action may include changes in demand (MW and MVar), energy (MWh and MVarh), or system configuration to maintain system stability, acceptable voltage, or power flows. An SPS does not include (a) underfrequency or undervoltage load shedding, (b) fault conditions that must be isolated, (c) out-of-step relaying not designed as an integral part of an SPS, or (d) Transmission Control Devices.

Stand Alone Network Upgrades shall mean Network Upgrades that an Interconnection Customer may construct without affecting day-to-day operations of the Transmission System during their construction. The Transmission Provider, Transmission Owner, and the Interconnection Customer must agree as to what constitutes Stand Alone Network Upgrades and identify them in Appendix A to this LGIA.

System Protection Facilities shall mean the equipment, including necessary protection signal communications equipment, required to protect (1) the Transmission System or other delivery systems or other generating systems from faults or other electrical disturbances occurring at the Generating Facility and (2) the Generating Facility from faults or other electrical system disturbances occurring on the Transmission System or on other delivery systems or other generating systems to which the Transmission System is directly connected.

Tariff shall mean the Transmission Provider’s Tariff through which open access transmission service and Interconnection Service are offered, as filed with the Commission, and as amended or supplemented from time to time, or any successor tariff.

Original Sheet No. 10

Transmission Control Devices shall mean a generally accepted transmission device that is planned and designed to provide dynamic control of electric system quantities, and are usually employed as solutions to specific system performance issues. Examples of such devices include fast valving, high response exciters, high voltage DC links, active or real power flow control and reactive compensation devices using power electronics (e.g., unified power flow controllers), static var compensators, thyristor controlled series capacitors, braking resistors, and in some cases mechanically switched capacitors and reactors. In general, such systems are not considered to be Special Protection Systems.

Transmission Owner shall mean that Transmission Owner as defined in the Tariff, which includes an entity that owns, leases, or otherwise possesses an interest in the portion of the Transmission System at which the Interconnection Customer proposes to interconnect or otherwise integrate the operation of the Generating Facility. Transmission Owner should be read to include any Independent Transmission Company that manages the transmission facilities of the Transmission Owner and shall include, as applicable, the owner and/or operator of distribution facilities interconnected to the Transmission System, over which facilities transmission service or Wholesale Distribution Service under the Tariff is available at the time the Interconnection Customer requests Interconnection Serviceand to which the Interconnection Customer has requested interconnection of a Generating Facility for the purpose of either transmitting electric energy in interstate commerce or selling electric energy at wholesale in interstate commerce.

Transmission Provider shall mean the Midcontinent Independent System Operator, Inc. (the “MISO”), the Regional Transmission Organization that controls or operates the transmission facilities of its transmission-owning members used for the transmission of electricity in interstate commerce and provides transmission service under the Tariff.

Transmission Owner’s Interconnection Facilities shall mean all facilities and equipment owned by the Transmission Owner from the Point of Change of Ownership to the Point of Interconnection as identified in Appendix A to this LGIA, including any modifications, additions or upgrades to such facilities and equipment. Transmission Owner’s Interconnection Facilities are sole use facilities and shall not include Distribution Upgrades, Generator Upgrades, Stand Alone Network Upgrades, or Network Upgrades.

Transmission System shall mean the facilities owned by the Transmission Owner and controlled or operated by the Transmission Provider or Transmission Owner that are used to provide transmission service or Wholesale Distribution Service under the Tariff.

Trial Operation shall mean the period during which Interconnection Customer is engaged in on-site test operations and commissioning of the Generating Facility prior to Commercial Operation.

Wholesale Distribution Service shall have that meaning as provided in the Tariff. Wherever the term “transmission delivery service” is used, Wholesale Distribution Service shall also be implied.

ARTICLE 2. EFFECTIVE DATE, TERM, AND TERMINATION

Original Sheet No. 11

2.1 Effective Date. This LGIA shall become effective upon execution by the Parties subject to acceptance by FERC (if applicable), or if filed unexecuted, upon the date specified by FERC. Transmission Provider shall promptly file this LGIA with FERC upon execution in accordance with Article 3.1, if required.

2.2 Term of Agreement. Subject to the provisions of Article 2.3, this LGIA shall remain in effect for a period of twenty (20) years from the Effective Date and shall be automatically renewed for each successive one-year period thereafter on the anniversary of the Effective Date.

2.3 Termination Procedures. This LGIA may be terminated as follows:

2.3.1 Written Notice. This LGIA may be terminated by Interconnection Customer after giving the Transmission Provider and Transmission Owner ninety (90) Calendar Days advance written notice or by Transmission Provider if the Generating Facility has ceased Commercial Operation for three (3) consecutive years, beginning with the last date of Commercial Operation for the Generating Facility, after giving the Interconnection Customer ninety (90) Calendar Days advance written notice. The Generating Facility will not be deemed to have ceased Commercial Operation for purposes of this Article 2.3.1 if the Interconnection Customer can document that it has taken other significant steps to maintain or restore operational readiness of the Generating Facility for the purpose of returning the Generating Facility to Commercial Operation as soon as possible.

2.3.2    Default. Any Party may terminate this LGIA in accordance with Article 17.

2.3.2 Notwithstanding Articles 2.3.1 and 2.3.2, no termination shall become effective until the Parties have complied with all Applicable Laws and Regulations applicable to such termination, including the filing with FERC of a notice of termination of this LGIA, if required, which notice has been accepted for filing by FERC.

2.4 Termination Costs. If a Party elects to terminate this LGIA pursuant to Article 2.3 above, each Party shall pay all costs incurred for which that Party is responsible (including any cancellation costs relating to orders or contracts for Interconnection Facilities, applicable upgrades, and related equipment) or charges assessed by the other Parties as of the date of the other Parties’ receipt of such notice of termination under this LGIA. In the event of termination by a Party, the Parties shall use commercially Reasonable Efforts to mitigate the costs, damages, and charges arising as a consequence of termination. Upon termination of this LGIA, unless otherwise ordered or approved by FERC:

2.4.1 With respect to any portion of the Transmission Owner's Interconnection Facilities, Network Upgrades, System Protection Facilities, Distribution Upgrades, Generator Upgrades, and if so determined and made a part of this LGIA, upgrades on Affected Systems, that have not yet been constructed or installed, the Transmission Owner shall to the extent possible and to the extent of Interconnection Customer's written notice under Article 2.3.1, cancel any pending orders of, or return, any materials or equipment for, or contracts for construction of, such facilities; provided that in the event Interconnection Customer elects not to authorize such cancellation, Interconnection Customer shall assume all payment

Original Sheet No. 12

obligations with respect to such materials, equipment, and contracts, and the Transmission Owner shall deliver such material and equipment, and, if necessary, assign such contracts, to Interconnection Customer as soon as practicable, at Interconnection Customer's expense. To the extent that Interconnection Customer has already paid Transmission Owner for any or all such costs of materials or equipment not taken by Interconnection Customer, Transmission Owner shall promptly refund such amounts to Interconnection Customer, less any costs, including penalties incurred by the Transmission Owner to cancel any pending orders of or return such materials, equipment, or contracts.

If an Interconnection Customer terminates this LGIA, it shall be responsible for all costs incurred in association with that Interconnection Customer’s interconnection, including any cancellation costs relating to orders or contracts for Interconnection Facilities and equipment, and other expenses including any upgrades or related equipment for which the Transmission Owner has incurred expenses and has not been reimbursed by the Interconnection Customer.

2.4.2 Transmission Owner may, at its option, retain any portion of such materials, equipment, or facilities that Interconnection Customer chooses not to accept delivery of, in which case Transmission Owner shall be responsible for all costs associated with procuring such materials, equipment, or facilities. If Transmission Owner does not so elect, then Interconnection Customer shall be responsible for such costs.

2.4.3 With respect to any portion of the Interconnection Facilities, and any other facilities already installed or constructed pursuant to the terms of this LGIA, Interconnection Customer shall be responsible for all costs associated with the removal, relocation, reconfiguration or other disposition or retirement of such materials, equipment, or facilities, and such other expenses actually incurred by Transmission Owner necessary to return the Transmission, Distribution or Generator System, as applicable, to safe and reliable operation.

2.5 Disconnection. Upon termination of this LGIA, the Parties will take all appropriate steps to disconnect the Generating Facility from the Transmission or Distribution System, as applicable. All costs required to effectuate such disconnection shall be borne by the terminating Party, unless such termination resulted from the non-terminating Party’s Default of this LGIA or such non-terminating Party otherwise is responsible for these costs under this LGIA.

2.6 Survival. This LGIA shall continue in effect after termination to the extent necessary to provide for final billings and payments and for costs incurred hereunder, including billings and payments pursuant to this LGIA; to permit the determination and enforcement of liability and indemnification obligations arising from acts or events that occurred while this LGIA was in effect; and to permit each Party to have access to the lands of the other Party pursuant to this LGIA or other applicable agreements, to disconnect, remove or salvage its own facilities and equipment.

ARTICLE 3. REGULATORY FILINGS

Original Sheet No. 13

3.1 Filing. The Transmission Provider shall file this LGIA (and any amendment hereto) with the appropriate Governmental Authority, if required. A Party may request that any information so provided be subject to the confidentiality provisions of Article 22. If that Party has executed this LGIA, or any amendment thereto, the Party shall reasonably cooperate with Transmission Provider with respect to such filing and to provide any information reasonably requested by Transmission Provider needed to comply with applicable regulatory requirements.

ARTICLE 4. SCOPE OF SERVICE

4.1 Interconnection Product Options. Interconnection Customer has selected the following (checked) type of Interconnection Service:

Check: __X__ER or _X___ NR

4.1.1 Energy Resource Interconnection Service (ER Interconnection Service).

4.1.1.1 The Product. ER Interconnection Service allows Interconnection Customer to connect the Generating Facility to the Transmission or Distribution System, as applicable, and be eligible to deliver the Generating Facility’s output using the existing firm or non-firm capacity of the Transmission System on an “as available” basis. To the extent Interconnection Customer wants to receive ER Interconnection Service, the Transmission Owner shall construct facilities consistent with the studies identified in Appendix A.

An Interconnection Customer seeking ER Interconnection Service for new or added capacity at a Generating Facility may be granted conditional ER Interconnection Service status to the extent there is such capacity available on the Transmission System to accommodate the Interconnection Customer’s Generating Facility. At the request of the Interconnection Customer, Conditional ER Interconnection Service status may be granted subject to the system being able to accommodate the interconnection without upgrades, until such time as a higher queued project(s) with a later service date affecting the same common elements is placed into service. The conditional ER Interconnection Service shall be terminated in the event the Interconnection Customer fails to fund the necessary studies and the Network Upgrades necessary to grant the Interconnection Customer’s ER Interconnection Service upon the completion of higher queued projects involving the same common elements.

4.1.1.2 Transmission Delivery Service Implications. Under ER Interconnection Service, the Interconnection Customer will be eligible to inject power from the Generating Facility into and deliver power across the Transmission System on an “as available” basis up to the amount of MW identified in the applicable stability and steady state studies to the extent the upgrades initially required to qualify for ER Interconnection Service have been constructed. After that date FERC makes effective the MISO’s Energy

Original Sheet No. 14

Market Tariff filed in Docket No. ER04‑691‑000, Interconnection Customer may place a bid to sell into the market up to the maximum identified Generating Facility output, subject to any conditions specified in the interconnection service approval, and the Generating Facility will be dispatched to the extent the Interconnection Customer’s bid clears. In all other instances, no transmission or other delivery service from the Generating Facility is assured, but the Interconnection Customer may obtain Point-To-Point Transmission Service, Network Integration Transmission Service or be used for secondary network transmission service, pursuant to the Tariff, up to the maximum output identified in the stability and steady state studies. In those instances, in order for the Interconnection Customer to obtain the right to deliver or inject energy beyond the Point of Interconnection or to improve its ability to do so, transmission delivery service must be obtained pursuant to the provisions of the Tariff. The Interconnection Customer’s ability to inject its Generating Facility output beyond the Point of Interconnection, therefore, will depend on the existing capacity of the Transmission or Distribution System as applicable, at such time as a transmission service request is made that would accommodate such delivery. The provision of Firm Point‑To‑Point Transmission Service or Network Integration Transmission Service may require the construction of additional Network or Distribution Upgrades.

4.1.2 Network Resource Interconnection Service (NR Interconnection Service).

4.1.2.1 The Product. The Transmission Provider must conduct the necessary studies and the Transmission Owner shall construct the facilities identified in Appendix A of this LGIA, subject to the approval of Governmental Authorities, needed to integrate the Generating Facility in the same manner as for any Large Generating Facility being designated as a Network Resource.

4.1.2.2 Transmission Delivery Service Implications. NR Interconnection Service allows the Generating Facility to be designated by any Network Customer under the Tariff on the Transmission System as a Network Resource, up to the Generating Facility's full output, on the same basis as existing Network Resources that are interconnected to the Transmission or Distribution System, as applicable, and to be studied as a Network Resource on the assumption that such a designation will occur. Although NR Interconnection Service does not convey a reservation of transmission service, any Network Customer can utilize network service under the Tariff to obtain delivery of energy from the Generating Facility in the same manner as it accesses Network Resources. A Generating Facility receiving NR Interconnection Service may also be used to provide Ancillary Services after technical studies and/or periodic analyses are performed with respect to the Generating Facility’s ability to provide any applicable Ancillary Services, provided that such studies and analyses have been or would be required in connection with the provision of such Ancillary Services by any existing Network Resource. However, if the

Original Sheet No. 15

Generating Facility has not been designated as a Network Resource by any Network Customer, it cannot be required to provide Ancillary Services except to the extent such requirements extend to all generating facilities that are similarly situated. The provision of Network Integration Transmission Service or Firm Point-To-Point Transmission Service may require additional studies and the construction of additional upgrades. Because such studies and upgrades would be associated with a request for delivery service under the Tariff, cost responsibility for the studies and upgrades would be in accordance with FERC’s policy for pricing transmission delivery services.

NR Interconnection Service does not necessarily provide the Interconnection Customer with the capability to physically deliver the output of its Generating Facility to any particular load on the Transmission System without incurring congestion costs. In the event of transmission or distribution constraints on the Transmission or Distribution System, as applicable, the Generating Facility shall be subject to the applicable congestion management procedures in the Transmission System in the same manner as Network Resources.

There is no requirement either at the time of study or interconnection, or at any point in the future, that the Generating Facility be designated as a Network Resource by a Network Customer or that the Interconnection Customer identify a specific buyer (or sink). To the extent a Network Customer does designate the Generating Facility as a Network Resource, it must do so pursuant to the Tariff.

Once an Interconnection Customer satisfies the requirements for obtaining NR Interconnection Service, any future transmission service request for delivery from the Generating Facility within the Transmission System of any amount of capacity and/or energy, up to the amount initially studied, will not require that any additional studies be performed or that any further upgrades associated with such Large Generating Facility be undertaken, regardless of whether such Large Generating Facility is ever designated by a Network Customer as a Network Resource and regardless of changes in ownership of the Generating Facility. To the extent the Interconnection Customer enters into an arrangement for long term transmission service for deliveries from the Generating Facility to customers other than the studied Network Customers, or for any Point-To-Point Transmission Service, such request may require additional studies and upgrades in order for the Transmission Provider to grant such request. However, the reduction or elimination of congestion or redispatch costs may require additional studies and the construction of additional upgrades.

To the extent the Interconnection Customer enters into an arrangement for long term transmission service for deliveries from the Generating Facility outside the Transmission System, such request may require additional

Original Sheet No. 16

studies and upgrades in order for the Transmission Provider to grant such request.

4.1.2.3 Conditional NR Interconnection Service. An Interconnection Customer seeking NR Interconnection Service for new or added capacity at a Generating Facility may be granted conditional NR Interconnection Service status to the extent there is such capacity available on the Transmission System to accommodate the Interconnection Customer’s Generating Facility. At the request of the Interconnection Customer, Conditional NR Interconnection Service status may be granted subject to the system being able to accommodate the interconnection without upgrades, until such time as higher queued project(s) with a later service date affecting the same common elements is placed into service. The conditional NR Interconnection Service status may be converted to ER Interconnection Service if either of the following occurs:

1) The Interconnection Customer fails to fund necessary studies and Network Upgrades required to allow the Interconnection Customer’s Generating Facility to receive NR Interconnection Service upon the completion of higher queued projects involving the same common elements; or

2) The higher queued project(s) or planned and required Network Upgrades are placed in service and the Network Upgrades required to provide NR Interconnection Service status to the Interconnection Customer’s Generating Facility are not in service.

In the event the Interconnection Customer fails to fund the necessary studies and Network Upgrades for NR Interconnection Service, the Interconnection Customer’s conditional NR Interconnection Service status shall be converted to ER Interconnection Service status unless the Interconnection Customer makes a new Interconnection Request. Such new Interconnection Request shall be evaluated in accordance with the LGIP and its new queue position priority.

Some or all of the conditional NR Interconnection Service status may be temporarily revoked if the Network Upgrades are not in service when the higher queued project(s) are placed in service. The availability of conditional NR Interconnection Service status will be determined by Transmission Provider’s studies. Upon funding and completion of the Network Upgrades required to establish the Generating Facility’s NR Interconnection Service status, the Generating Facility will be granted NR Interconnection Service status.

The Parties agree that the portion of the Generating Facility classified as NR Interconnection Service is the first portion of the output of the combined output of all the units at the Generating Facility except in circumstances where the Interconnection Customer otherwise elects in the Agreement, as amended, to allocate that portion to the output of specific unit(s) at the Generating Facility, the total of which will not exceed

Original Sheet No. 17

the output eligible for NR Interconnection Service as shown by the additional studies. To the extent Interconnection Customer desires to obtain NR Interconnection Service for any portion of the Generating Facility in addition to that supported by such additional studies, the Interconnection Customer will be required to request such additional NR Interconnection Service through a separate Interconnection Request in accordance with the LGIP.

4.2 Provision of Service. Transmission Provider shall provide Interconnection Service for the Generating Facility at the Point of Interconnection.

4.3 Performance Standards. Each Party shall perform all of its obligations under this LGIA in accordance with Applicable Laws and Regulations, Applicable Reliability Standards, and Good Utility Practice. To the extent a Party is required or prevented or limited in taking any action by such regulations and standards, or if the obligations of any Party may become limited by a change in Applicable Laws and Regulations, Applicable Reliability Standards, and Good Utility Practice after the execution of this LGIA, that Party shall not be deemed to be in Breach of this LGIA for its compliance therewith. The Party so limited shall notify the other Parties whereupon the Transmission Provider shall amend this LGIA in concurrence with the other Parties and submit the amendment to the Commission for approval.

4.4 No Transmission Delivery Service. The execution of this LGIA does not constitute a request for, nor the provision of, any transmission delivery service under the Tariff, and does not convey any right to deliver electricity to any specific customer or Point of Delivery.

4.5 Interconnection Customer Provided Services. The services provided by Interconnection Customer under this LGIA are set forth in Article 9.6 and Article 13.5.1. Interconnection Customer shall be paid for such services in accordance with Article 11.6.

ARTICLE 5. INTERCONNECTION FACILITIES ENGINEERING, PROCUREMENT, AND CONSTRUCTION

5.1 Options. Unless otherwise mutually agreed to between the Parties, Interconnection Customer shall select: 1) the In-Service Date, Initial Synchronization Date, and Commercial Operation Date based on a reasonable construction schedule that will allow sufficient time for design, construction, equipment procurement, and permit acquisition of Transmission System equipment or right-of-way; and 2) either Standard Option or Alternate Option set forth below for completion of the Transmission Owner’s Interconnection Facilities, Network Upgrades, System Protection Facilities, Distribution Upgrades and Generator Upgrades, as applicable, and set forth in Appendix A, and such dates and selected option shall be set forth in Appendix B. The dates and selected option shall be subject to the acceptance of the Transmission Owner taking into account the type of construction to be employed and the regulatory requirements

Original Sheet No. 18

of Governmental Authority, and does not convey any right to deliver electricity to any specific customer or Point of Delivery, including the need to obtain permits or other authorizations for construction of the Interconnection Facilities, Network

Upgrades, System Protection Facilities, Distribution Upgrades, Generator Upgrades, the Generating Facility and Stand-Alone Network Upgrades.

5.1.1 Standard Option. The Transmission Owner shall design, procure, and construct the Transmission Owner’s Interconnection Facilities, Network Upgrades, System Protection Facilities, Distribution Upgrades, and Generator Upgrades using Reasonable Efforts to complete the Transmission Owner’s Interconnection Facilities, Network Upgrades, System Protection Facilities, Distribution Upgrades and Generator Upgrades by the dates set forth in Appendix B, Milestones, subject to the receipt of all approvals required from Governmental Authorities and the receipt of all land rights necessary to commence construction of such facilities, and such other permits or authorizations as may be required. The Transmission Provider or Transmission Owner shall not be required to undertake any action which is inconsistent with its standard safety practices, its material and equipment specifications, its design criteria and construction procedures, its labor agreements, Applicable Laws and Regulations and Good Utility Practice. In the event the Transmission Owner reasonably expects that it will not be able to complete the Transmission Owner’s Interconnection Facilities, Network Upgrades, System Protection Facilities, Distribution Upgrades and Generator Upgrades by the specified dates, the Transmission Owner shall promptly provide written notice to the Interconnection Customer and Transmission Provider and shall undertake Reasonable Efforts to meet the earliest dates thereafter.

5.1.2 Alternate Option. If the dates designated by Interconnection Customer are acceptable to Transmission Provider and Transmission Owner, the Transmission Provider shall so notify Interconnection Customer within thirty (30) Calendar Days, and Transmission Owner shall assume responsibility for the design, procurement and construction of the Transmission Owner’s Interconnection Facilities by the designated dates.

If Transmission Owner subsequently fails to complete Transmission Owner’s Interconnection Facilities by the In-Service Date, to the extent necessary to provide back feed power; or fails to complete Network Upgrades by the Initial Synchronization Date to the extent necessary to allow for Trial Operation at full power output, unless other arrangements are made by the Parties for such Trial Operation; or fails to complete the Network Upgrades by the Commercial Operation Date, as such dates are reflected in Appendix B, Milestones; Transmission Owner shall pay Interconnection Customer liquidated damages in accordance with Article 5.3, Liquidated Damages, provided, however, the dates designated by Interconnection Customer shall be extended day for day for each day that the Transmission Provider refuses to grant clearances to install equipment.

Original Sheet No. 19

The Transmission Owner and Interconnection Customer may adopt an incentive payment schedule that is mutually agreeable to encourage the Transmission Owner to meet specified accelerated dates. Such payment by the Interconnection Customer is not subject to refund.

5.1.3 Option to Build. If the dates designated by Interconnection Customer are not acceptable to Transmission Owner to complete the Transmission Owner’s Interconnection Facilities or Stand Alone Network Upgrades, the Transmission Provider shall so notify the Interconnection Customer within thirty (30) Calendar Days, and unless the Parties agree otherwise, Interconnection Customer shall have the option to assume responsibility for the design, procurement and construction of Transmission Owner’s Interconnection Facilities and Stand Alone Network Upgrades by the dates originally designated by the Interconnection Customer under Article 5.1.2. The Parties must agree as to what constitutes Stand Alone Network Upgrades and identify such Stand Alone Network Upgrades in Appendix A. Except for Stand Alone Network Upgrades, Interconnection Customer shall have no right to construct Network Upgrades under this option.

5.1.4 Negotiated Option. If the Interconnection Customer elects not to exercise its option under Article 5.1.3, Option to Build, Interconnection Customer shall so notify Transmission Provider and Transmission Owner within thirty (30) Calendar Days, and the Parties shall in good faith attempt to negotiate terms and conditions (including revision of the specified dates and liquidated damages, the provision of incentives or the procurement and construction of a portion of the Transmission Owner’s Interconnection Facilities and Stand Alone Network Upgrades by Interconnection Customer) pursuant to which Transmission Owner is responsible for the design, procurement and construction of the Transmission Owner’s Interconnection Facilities and Network Upgrades. If the Parties are unable to reach agreement on such terms and conditions, Transmission Owner shall assume responsibility for the design, procurement and construction of the Transmission Owner’s Interconnection Facilities and Network Upgrades pursuant to 5.1.1, Standard Option.

The Transmission Owner and Interconnection Customer may adopt an incentive payment schedule that is mutually agreeable to encourage the Transmission Owner to meet specified accelerated dates. Such payment by the Interconnection Customer is not subject to refund.

5.2 General Conditions Applicable to Option to Build. If Interconnection Customer assumes responsibility for the design, procurement and construction of the Transmission Owner’s Interconnection Facilities and Stand Alone Network Upgrades after receipt of all required approvals from Governmental Authorities necessary to commence construction,

(1) the Interconnection Customer shall engineer, procure equipment, and construct the Transmission Owner’s Interconnection Facilities and Stand Alone Network Upgrades (or portions thereof) using Good Utility Practice and using standards and specifications provided in advance by the Transmission Owner, or as required by any Governmental Authority;

Original Sheet No. 20

(2) Interconnection Customer’s engineering, procurement and construction of the Transmission Owner’s Interconnection Facilities and Stand Alone Network Upgrades shall comply with all requirements of law or Governmental Authority to which Transmission Owner would be subject in the engineering, procurement or construction of the Transmission Owner’s Interconnection Facilities and Stand Alone Network Upgrades;

(3) Transmission Provider, at Transmission Provider’s option, and Transmission Owner shall be entitled to review and approve the engineering design, equipment acceptance tests(including witnessing of acceptance tests), and the construction (including monitoring of construction) of the Transmission Owner’s Interconnection Facilities and Stand Alone Network Upgrades, and shall have the right to reject any design, procurement, construction or acceptance test of any equipment that does not meet the standards and specifications of Transmission Provider, Transmission Owner and any Governmental Authority;

(4) prior to commencement of construction, Interconnection Customer shall provide to Transmission Provider and Transmission Owner a schedule for construction of the Transmission Owner’s Interconnection Facilities and Stand Alone Network Upgrades, and shall promptly respond to requests for information from Transmission Provider and Transmission Owner;

(5) at any time during construction, Transmission Provider and Transmission Owner shall have unrestricted access to the construction site for the Transmission Provider's Interconnection Facilities and Stand Alone Network Upgrades and to conduct inspections of the same;(6) at any time during construction, should any phase of the engineering, equipment procurement, or construction of the Transmission Owner’s Interconnection Facilities and Stand Alone Network Upgrades not meet the standards and specifications provided by Transmission Owner, the Interconnection Customer shall be obligated to remedy deficiencies in that portion of the Transmission Owner’s Interconnection Facilities and Stand Alone Network Upgrades to meet the standards and specifications provided by Transmission Provider and Transmission Owner;

(7) the Interconnection Customer shall indemnify the Transmission Provider and Transmission Owner for claims arising from the Interconnection Customer's construction of Transmission Owner’s Interconnection Facilities and Stand Alone Network Upgrades under the terms and procedures applicable to Article 18.1, Indemnity;

(8) the Interconnection Customer shall transfer control of Transmission Owner’s Interconnection Facilities and Stand Alone Network Upgrades to the Transmission Owner;

(9) Unless Parties otherwise agree, Interconnection Customer shall transfer ownership of Transmission Owner’s Interconnection Facilities and Stand Alone Network Upgrades to the Transmission Owner;

(10) Transmission Provider, at Transmission Provider’s option, and Transmission Owner shall approve and accept for operation and maintenance the Transmission

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Owner’s Interconnection Facilities and Stand Alone Network Upgrades to the extent engineered, procured, and constructed in accordance with this Article 5.2 only if the Transmission Owner's Interconnection Facilities and Stand Alone Network Upgrades meet the standards and specifications of Transmission Provider, Transmission Owner and any Governmental Authority.

(11) Interconnection Customer shall deliver to Transmission Provider “as‑built” drawings, information, and any other documents that are reasonably required by Transmission Provider to assure that the Interconnection Facilities and Stand‑Alone Network Upgrades are built to the standards and specifications required by Transmission Provider.

5.3 Liquidated Damages. The actual damages to the Interconnection Customer, in the event the Transmission Owner’s Interconnection Facilities or Network Upgrades are not completed by the dates designated by the Interconnection Customer and accepted by the Transmission Provider and Transmission Owner pursuant to subparagraphs 5.1.2 or 5.1.4, above, may include Interconnection Customer’s fixed operation and maintenance costs and lost opportunity costs. Such actual damages are uncertain and impossible to determine at this time. Because of such uncertainty, any liquidated damages paid by the Transmission Owner to the Interconnection Customer in the event that Transmission Owner does not complete any portion of the Transmission Owner’s Interconnection Facilities or Network Upgrades by the applicable dates, shall be an amount equal to ½ of 1 percent per day of the actual cost of the Transmission Owner’s Interconnection Facilities and Network Upgrades, in the aggregate, for which Transmission Owner has assumed responsibility to design, procure and construct.

However, in no event shall the total liquidated damages exceed 20 percent of the actual cost of the Transmission Owner’s Interconnection Facilities and Network Upgrades for which the Transmission Owner has assumed responsibility to design, procure, and construct. The foregoing payments will be made by the Transmission Owner to the Interconnection Customer as just compensation for the damages caused to the Interconnection Customer, which actual damages are uncertain and impossible to determine at this time, and as reasonable liquidated damages, but not as a penalty or a method to secure performance of this LGIA. Liquidated damages, when the Parties agree to them, are the exclusive remedy for the Transmission Owner’s failure to meet its schedule.

No liquidated damages shall be paid to Interconnection Customer if: (1) Interconnection Customer is not ready to commence use of the Transmission Owner’s Interconnection Facilities or Network Upgrades to take the delivery of power for the Generating Facility's Trial Operation or to export power from the Generating Facility on the specified dates, unless the Interconnection Customer would have been able to commence use of the Transmission Owner’s Interconnection Facilities or Network Upgrades to take the delivery of power for Generating Facility's Trial Operation or to export power from the Generating Facility, but for Transmission Owner’s delay; (2) the Transmission Owner’s failure to meet the specified dates is the result of the action or inaction of the Transmission Provider, the Interconnection Customer or any other earlier queued Interconnection Customer who has entered into an earlier LGIA with the Transmission Provider and/or a Transmission Owner or with an Affected System Operator, or any cause beyond Transmission Owner’s

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reasonable control or reasonable ability to cure; (3) the Interconnection Customer has assumed responsibility for the design, procurement and construction of the Transmission Owner’s Interconnection Facilities and Stand Alone Network Upgrades; (4) the delay is due to the inability of the Transmission Owner to obtain all required approvals from Governmental Authorities in a timely manner for the construction of any element of the Interconnection Facilities, Network Upgrades or Stand Alone Network Upgrades, or any other permit or authorization required, or any land rights or other private authorizations that may be required, and Transmission Owner has exercised Reasonable Efforts in procuring such approvals, permits, rights or authorizations; or (5) the Parties have otherwise agreed.

5.4 Power System Stabilizers. The Interconnection Customer shall procure, install, maintain and operate power system stabilizers in accordance with the guidelines and procedures established by the Applicable Reliability Council. Transmission Provider and Transmission Owner reserve the right to reasonably establish minimum acceptable settings for any installed power system stabilizers, subject to the design and operating limitations of the Generating Facility. If the Generating Facility’s power system stabilizers are removed from service or are not capable of automatic operation, the Interconnection Customer shall immediately notify the Transmission Provider’s system operator, or its designated representative. The requirements of this paragraph shall not apply to induction generators.

5.5 Equipment Procurement. If responsibility for construction of the Transmission Owner’s Interconnection Facilities, Network Upgrades and/or Distribution Upgrades is to be borne by the Transmission Owner, then the Transmission Owner shall commence design of the Transmission Owner’s Interconnection Facilities, Network Upgrades and/or Distribution Upgrades, and procure necessary equipment as soon as practicable after all of the following conditions are satisfied, unless the Parties otherwise agree in writing:

5.5.1 The Transmission Provider has completed the Interconnection Facilities Study pursuant to the Interconnection Facilities Study Agreement;

5.5.2 The Transmission Provider has received written authorization from the Interconnection Customer by the date specified in Appendix B, Milestones, for Transmission Owner to proceed with design and procurement; and

5.5.3 The Interconnection Customer has provided security to the Transmission Owner, with notice provided to Transmission Provider, in accordance with Article 11.5 by the dates specified in Appendix B, Milestones.

5.6 Construction Commencement. The Transmission Owner shall commence construction of the Transmission Owner’s Interconnection Facilities, Network Upgrades, Transmission Owner’s System Protection Facilities, Distribution Upgrades, and Generator Upgrades for which it is responsible as soon as practicable after the following additional conditions are satisfied:

5.6.1 Approval of the appropriate Governmental Authority has been obtained for any facilities requiring regulatory approval;

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5.6.2 Necessary real property rights and rights-of-way have been obtained, to the extent required for the construction of a discrete aspect of the Transmission Owner’s Interconnection Facilities, Network Upgrades and Distribution Upgrades;

5.6.3 The Transmission Provider has received written authorization from the Interconnection Customer by the date specified in Appendix B, Milestones, for Transmission Owner to proceed with its construction; and

5.6.4 The Interconnection Customer has provided security to the Transmission Owner, with notice to Transmission Provider, in accordance with Article 11.5 by the dates specified in Appendix B, Milestones.

5.7 Work Progress. Transmission Owner and Interconnection Customer will keep each other and Transmission Provider advised periodically as to the progress of their respective design, procurement, and construction efforts. Either Transmission Owner or Interconnection Customer may, at any time, request a progress report from the other, with a copy to be provided to the other Parties. If, at any time, the Interconnection Customer determines that the completion of the Transmission Owner’s Interconnection Facilities, Network Upgrades, or Transmission Owner’s System Protection Facilities will not be required until after the specified In-Service Date, the Interconnection Customer will provide written notice to the Transmission Provider and Transmission Owner of such later date upon which the completion of the Transmission Owner’s Interconnection Facilities, Network Upgrades, or Transmission Owner’s System Protection Facilities will be required. The Transmission Owner may delay the In-Service Date of its facilities accordingly.

5.8 Information Exchange. As soon as reasonably practicable after the Effective Date, the Parties shall exchange information regarding the design and compatibility of the Interconnection Facilities and compatibility of the Interconnection Facilities with the Transmission System or Distribution System, as applicable, and shall work diligently and in good faith to make any necessary design changes.

5.9 Limited Operation. If any of the Transmission Owner’s Interconnection Facilities, Network Upgrades, or Transmission Owner’s System Protection Facilities, Distribution Upgrades, or Generator Upgrades are not reasonably expected to be completed prior to the Commercial Operation Date of the Generating Facility, Transmission Provider shall, upon the request and at the expense of Interconnection Customer, perform Operating Studies on a timely basis to determine the extent to which the Generating Facility and the Interconnection Customer Interconnection Facilities may operate prior to the completion of the Transmission Owner’s Interconnection Facilities, Network Upgrades, Transmission Owner’s System Protection Facilities, Distribution Upgrades, or Generator Upgrades consistent with Applicable Laws and Regulations, Applicable Reliability Standards, Good Utility Practice, and this LGIA. Transmission Provider and Transmission Owner shall permit Interconnection Customer to operate the Generating Facility and the Interconnection Customer’s Interconnection Facilities in accordance with the results of such studies; provided, however, such studies reveal that such operation may occur without detriment to the Transmission System as then configured and in accordance with the safety requirements of Transmission Owner and any Governmental Authority.

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5.10 Interconnection Customer's Interconnection Facilities (“ICIF”). Interconnection Customer shall, at its expense, design, procure, construct, own and install the ICIF, as set forth in Appendix A.

5.10.1 Interconnection Customer’s Interconnection Facility Specifications. Interconnection Customer shall submit initial design and specifications for the ICIF, including Interconnection Customer’s System Protection Facilities, to Transmission Provider and Transmission Owner at least one hundred eighty (180) Calendar Days prior to the Initial Synchronization Date; and final design and specifications for review and comment at least ninety (90) Calendar Days prior to the Initial Synchronization Date. Transmission Provider at Transmission Provider’s option, and Transmission Owner shall review such specifications to ensure that the ICIF are compatible with their respective technical specifications, operational control, and safety requirements and comment on such design and specifications within thirty (30) Calendar Days of Interconnection Customer's submission. All specifications provided hereunder shall be deemed confidential.

5.10.2 Transmission Provider’s and Transmission Owner’s Review. Transmission Provider’s and Transmission Owner’s review of Interconnection Customer's final specifications shall not be construed as confirming, endorsing, or providing a warranty as to the design, fitness, safety, durability or reliability of the Generating Facility, or the ICIF. Interconnection Customer shall make such changes to the ICIF as may reasonably be required by Transmission Provider and Transmission Owner, in accordance with Good Utility Practice, to ensure that the ICIF are compatible with the technical specifications, operational control and safety requirements of Transmission Provider and Transmission Owner.

5.10.3 ICIF Construction. The ICIF shall be designed and constructed in accordance with Good Utility Practice. Within one hundred twenty (120) Calendar Days after the Commercial Operation Date, unless the Parties agree on another mutually acceptable deadline, the Interconnection Customer shall deliver to the Transmission Provider and Transmission Owner “as-built” drawings, information and documents for the ICIF, such as: a one-line diagram, a site plan showing the Generating Facility and the ICIF, plan and elevation drawings showing the layout of the ICIF, a relay functional diagram, relaying AC and DC schematic wiring diagrams and relay settings for all facilities associated with the Interconnection Customer's step-up transformers, the facilities connecting the Generating Facility to the step-up transformers and the ICIF, and the impedances (determined by factory tests) for the associated step-up transformers and the Generating Facility. The Interconnection Customer shall provide Transmission Provider and Transmission Owner with Interconnection Customer’s specifications for the excitation system, automatic voltage regulator, Generating Facility control and protection settings, transformer tap settings, and communications, if applicable.

5.11 Transmission Owner’s Interconnection Facilities Construction. The Transmission Owner’s Interconnection Facilities shall be designed and constructed in accordance with Good Utility Practice. Upon request, within one hundred twenty (120) Calendar Days after the Commercial Operation Date, unless the Parties agree on another mutually acceptable deadline, the Transmission Owner shall deliver to the Transmission Provider

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and Interconnection Customer the following “as-built” drawings, information and documents for the Transmission Owner’s Interconnection Facilities specified in Appendix C to this LGIA.

Such drawings, information and documents shall be deemed Confidential Information.

Upon completion, the Transmission Owner’s Interconnection Facilities and Stand Alone Network Upgrades shall be under the control of the Transmission Provider or its designated representative.

5.12 Access Rights. Upon reasonable notice by a Party, and subject to any required or necessary regulatory approvals, a Party (“Granting Party”) shall furnish at no cost to the other Party (“Access Party”) any rights ofuse, licenses, rights of way and easements with respect to lands owned or controlled by the Granting Party, its agents (if allowed under the applicable agency agreement), or any Affiliate, that are necessary to enable the Access Party to obtain ingress and egress to construct, operate, maintain, repair, test (or witness testing), inspect, replace or remove facilities and equipment to: (i) interconnect the Generating Facility with the Transmission System; (ii) operate and maintain the Generating Facility, the Interconnection Facilities and the Transmission System; and (iii) disconnect or remove the Access Party’s facilities and equipment upon termination of this LGIA. In exercising such licenses, rights of way and easements, the Access Party shall not unreasonably disrupt or interfere with normal operation of the Granting Party’s business and shall adhere to the safety rules and procedures established in advance, as may be changed from time to time, by the Granting Party and provided to the Access Party.

5.13 Lands of Other Property Owners. If any part of the Transmission Owner's Interconnection Facilities, Network Upgrades, and/or Distribution Upgrades is to be installed on property owned by persons other than Interconnection Customer or Transmission Owner, the Transmission Owner shall at Interconnection Customer's expense use efforts, similar in nature and extent to those that it typically undertakes on its own behalf or on behalf of its Affiliates, including use of its eminent domain authority to the extent permitted and consistent with Applicable Laws and Regulations and, to the extent consistent with such Applicable Laws and Regulations, to procure from such persons any rights of use, licenses, rights of way and easements that are necessary to construct, operate, maintain, test, inspect, replace or remove the Transmission Owner's Interconnection Facilities, Network Upgrades and/or Distribution Upgrades upon such property.

5.14 Permits. Transmission Provider or Transmission Owner and Interconnection Customer shall cooperate with each other in good faith in obtaining all permits, licenses and authorizations that are necessary to accomplish the interconnection in compliance with Applicable Laws and Regulations. With respect to this paragraph, Transmission Owner shall provide permitting assistance to the Interconnection Customer comparable to that provided to the Transmission Owner’s own, or an Affiliate's generation, to the extent that Transmission Owner or its Affiliate owns generation.

5.15 Early Construction of Base Case Facilities. Interconnection Customer may request Transmission Owner to construct, and Transmission Owner shall construct, using Reasonable Efforts to accommodate Interconnection Customer's In-Service Date, all or

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any portion of any Network Upgrades, Transmission Owner’s System Protection Facilities or Distribution Upgrades required for Interconnection Customer to be interconnected to the Transmission or Distribution System, as applicable, which are included in the Base Case of the Interconnection Facilities Study for the Interconnection Customer, and which also are required to be constructed for another Interconnection Customer, but where such construction is not scheduled to be completed in time to achieve Interconnection Customer's In-Service Date. Any such Network Upgrades, System Protection Facilities or Distribution Upgrades are included in the facilities to be constructed and as set forth in Appendix A to this LGIA.

5.16 Suspension.

5.16.1 Interconnection Customer’s Right to Suspend; Obligations. Provided that such suspension is permissible under the authorizations, permits or approvals granted for the construction of such Interconnection Facilities, Network Upgrades or Stand Alone Network Upgrades, Interconnection Customer reserves the right upon written notice to Transmission Provider and Transmission Owner, to suspend at any time all work by Transmission Owner associated with the construction and installation of Transmission Owner's Interconnection Facilities, Network Upgrades, Transmission Owner’s System Protection Facilities, Distribution Upgrades and/or Generator Upgrades required under this LGIA with the condition that the Transmission or Distribution System, as applicable, shall be left in a safe and reliable condition in accordance with Good Utility Practice and the Transmission Provider’s and Transmission Owner‘s safety and reliability criteria. In such event, Interconnection Customer shall be responsible for all reasonable and necessary costs which Transmission Provider and Transmission Owner (i) have incurred pursuant to this LGIA prior to the suspension and (ii) incur in suspending such work, including any costs incurred to perform such work as may be necessary to ensure the safety of persons and property and the integrity of the Transmission or Distribution System, as applicable, during such suspension and, if applicable, any costs incurred in connection with the cancellation or suspension of material, equipment and labor contracts which Transmission Provider and Transmission Owner cannot reasonably avoid; provided, however, that prior to canceling or suspending any such material, equipment or labor contract, Transmission Provider and Transmission Owner shall obtain Interconnection Customer's authorization to do so.

Transmission Provider and Transmission Owner shall each invoice Interconnection Customer for such costs pursuant to Article 12 and shall use Reasonable Efforts to minimize its costs. In the event Interconnection Customer suspends work by Transmission Owner required under this LGIA pursuant to this Article 5.16, and has not requested Transmission Owner to recommence the work required under this LGIA on or before the expiration of three (3) years following commencement of such suspension, this LGIA shall be deemed terminated. The three-year period shall begin on the date the suspension is requested, or the date of the written notice to Transmission Provider, if no effective date is specified.

5.16.2 Effect of Missed Interconnection Customer Milestones. If Interconnection Customer fails to provide notice of suspension pursuant to Article

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5.16, and Interconnection Customer fails to fulfill or complete any Interconnection Customer Milestone provided in Appendix B (“Milestone”), this constitutes a Breach under this LGIA. Depending upon the consequences of the Breach and effectiveness of the cure pursuant to Article 17, the Transmission Owners’ Milestones may be revised, following consultation with the Interconnection Customer, consistent with Reasonable Efforts, and in consideration of all relevant circumstances. Parties shall employ Reasonable Efforts to maintain their remaining respective Milestones.

5.16.3 Effect of Suspension; Parties Obligations. In the event that Interconnection Customer suspends work pursuant to this Article 5.16, all construction duration, timelines and schedules set forth in Appendix B shall be suspended during the period of suspension. Should Interconnection Customer request that work be recommenced, Transmission Owner shall be obligated to proceed with Reasonable Efforts and in consideration of all relevant circumstances including regional outage schedules, construction availability and material procurement in performing the work as described in Appendix A and Appendix B. Transmission Owner will provide Interconnection Customer with a revised schedule for the design, procurement, construction, installation and testing of the Transmission Owner’s Interconnection Facilities and Network Upgrades. Upon any suspension by Interconnection Customer pursuant to Article 5.16, Interconnection Customer shall be responsible for only those costs specified in this Article 5.16.

5.17Taxes.

5.17.1 Interconnection Customer Payments Not Taxable. The Parties intend that all payments or property transfers made by Interconnection Customer to Transmission Owner for the installation of the Transmission Owner’s Interconnection Facilities, Network Upgrades, Transmission Owner’s System Protection Facilities, Distribution Upgrades and Generator Upgrades shall be non-taxable, either as contributions to capital, or as an advance, in accordance with the Internal Revenue Code and any applicable state income tax laws and shall not be taxable as contributions in aid of construction or otherwise under the Internal Revenue Code and any applicable state income tax laws.

5.17.2 Representations and Covenants. In accordance with IRS Notice 2001-82 and IRS Notice 88-129, Interconnection Customer represents and covenants that (i) ownership of the electricity generated at the Generating Facility will pass to another party prior to the transmission of the electricity on the Transmission System, (ii) for income tax purposes, the amount of any payments and the cost of any property transferred to the Transmission Owner for the Transmission Owner’s Interconnection Facilities will be capitalized by Interconnection Customer as an intangible asset and recovered using the straight-line method over a useful life of twenty (20) years, and (iii) any portion of the Transmission Owner's Interconnection Facilities that is a “dual-use intertie,” within the meaning of IRS Notice 88-129, is reasonably expected to carry only a de minimis amount of electricity in the direction of the Generating Facility. For this purpose, “de minimis amount” means no more than 5 percent of the total power flows in both directions,

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calculated in accordance with the “5 percent test” set forth in IRS Notice 88-129. This is not intended to be an exclusive list of the relevant conditions that must be met to conform to IRS requirements for non-taxable treatment.

At Transmission Owner’s request, Interconnection Customer shall provide Transmission Owner with a report from an independent engineer confirming its representation in clause (iii), above, with a copy to Transmission Provider. Transmission Owner represents and covenants that the cost of the Transmission Owner’s Interconnection Facilities paid for by Interconnection Customer will have no net effect on the base upon which rates are determined.

5.17.3 Indemnification for the Cost Consequences of Current Tax Liability Upon Transmission Owner. Notwithstanding Article 5.17.1, Interconnection Customer shall protect, indemnify and hold harmless Transmission Owner from the cost consequences of any tax liability imposed against Transmission Owner as the result of payments or property transfers made by Interconnection Customer to Transmission Owner under this LGIA for Interconnection Facilities, as well as any interest and penalties, other than interest and penalties attributable to any delay caused by Transmission Owner.

Transmission Owner shall not include a gross-up for the cost consequences of any current tax liability in the amounts it charges Interconnection Customer under this LGIA unless (i) Transmission Owner has determined, in good faith, that the payments or property transfers made by Interconnection Customer to Transmission Owner should be reported as income subject to taxation or (ii) any Governmental Authority directs Transmission Owner to report payments or property as income subject to taxation; provided, however, that Transmission Owner may require Interconnection Customer to provide security for Interconnection Facilities, in a form reasonably acceptable to Transmission Owner (such as a parental guarantee or a letter of credit), in an amount equal to the cost consequences or any current tax liability under this Article 5.17. Interconnection Customer shall reimburse Transmission Owner for such costs on a fully grossed-up basis, in accordance with Article 5.17.4, within thirty (30) Calendar Days of receiving written notification from Transmission Owner of the amount due, including detail about how the amount was calculated.

The indemnification obligation shall terminate at the earlier of (1) the expiration of the ten-year testing period and the applicable statute of limitation, as it may be extended by the Transmission Owner upon request of the IRS, to keep these years open for audit or adjustment, or (2) the occurrence of a subsequent taxable event and the payment of any related indemnification obligations as contemplated by this Article 5.17.

5.17.4 Tax Gross-Up Amount. Interconnection Customer's liability for the cost consequences of any current tax liability under this Article 5.17 shall be calculated on a fully grossed-up basis. Except as may otherwise be agreed to by the parties, this means that Interconnection Customer will pay Transmission Owner, in addition to the amount paid for the Interconnection Facilities, Network Upgrades, Transmission Owner’s System Protection Facilities, and/or Distribution Upgrades, an amount equal to (1) the current taxes imposed on

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Transmission Owner (“Current Taxes”) on the excess of (a) the gross income realized by Transmission Owner as a result of payments or property transfers made by Interconnection Customer to Transmission Owner under this LGIA (without regard to any payments under this Article 5.17) (the “Gross Income Amount”) over (b) the present value of future tax deductions for depreciation that will be available as a result of such payments or property transfers (the “Present Value Depreciation Amount”), plus (2) an additional amount sufficient to permit the Transmission Owner to receive and retain, after the payment of all Current Taxes, an amount equal to the net amount described in clause (1).

For this purpose, (i) Current Taxes shall be computed based on Transmission Owner’s composite federal and state tax rates at the time the payments or property transfers are received and Transmission Owner will be treated as being subject to tax at the highest marginal rates in effect at that time (the “Current Tax Rate”), and (ii) the Present Value Depreciation Amount shall be computed by discounting Transmission Owner’s anticipated tax depreciation deductions as a result of such payments or property transfers by Transmission Owner’s current weighted average cost of capital. Thus, the formula for calculating Interconnection Customer's liability to Transmission Owner pursuant to this Article 5.17.4 can be expressed as follows: (Current Tax Rate x (Gross Income Amount - Present Value of Tax Depreciation))/(1-Current Tax Rate). Interconnection Customer's estimated tax liability in the event taxes are imposed shall be stated in Appendix A, Interconnection Facilities, Network Upgrades and Distribution Upgrades.

5.17.5 Private Letter Ruling or Change or Clarification of Law. At Interconnection Customer's request and expense, Transmission Owner shall file with the IRS a request for a private letter ruling as to whether any property transferred or sums paid, or to be paid, by Interconnection Customer to Transmission Owner under this LGIA are subject to federal income taxation. Interconnection Customer will prepare the initial draft of the request for a private letter ruling, and will certify under penalties of perjury that all facts represented in such request are true and accurate to the best of Interconnection Customer's knowledge. Transmission Owner and Interconnection Customer shall cooperate in good faith with respect to the submission of such request.

Transmission Owner shall keep Interconnection Customer fully informed of the status of such request for a private letter ruling and shall execute either a privacy act waiver or a limited power of attorney, in a form acceptable to the IRS, that authorizes Interconnection Customer to participate in all discussions with the IRS regarding such request for a private letter ruling. Transmission Owner shall allow Interconnection Customer to attend all meetings with IRS officials about the request and shall permit Interconnection Customer to prepare the initial drafts of any follow-up letters in connection with the request.

5.17.6 Subsequent Taxable Events. If, within 10 years from the date on which the relevant Transmission Owner’s Interconnection Facilities are placed in service, (i) Interconnection Customer Breaches the covenant contained in Article 5.17.2, (ii) a "disqualification event" occurs within the meaning of IRS Notice 88-129, or (iii)

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this LGIA terminates and Transmission Owner retains ownership of the Interconnection Facilities, Network Upgrades, Transmission Owner’s System Protection Facilities, and/or Distribution Upgrades, the Interconnection Customer shall pay a tax gross-up for the cost consequences of any current tax liability imposed on Transmission Owner, calculated using the methodology described in Article 5.17.4 and in accordance with IRS Notice 90‑60.

5.17.7 Contests. In the event any Governmental Authority determines that Transmission Owner’s receipt of payments or property constitutes income that is subject to taxation, Transmission Owner shall notify Interconnection Customer, in writing, within thirty (30) Calendar Days of receiving notification of such determination by a Governmental Authority. Upon the timely written request by Interconnection Customer and at Interconnection Customer's sole expense, Transmission Owner may appeal, protest, seek abatement of, or otherwise oppose such determination. Upon Interconnection Customer's written request and sole expense, Transmission Owner shall file a claim for refund with respect to any taxes paid under this Article 5.17, whether or not it has received such a determination. Transmission Owner reserves the right to make all decisions with regard to the prosecution of such appeal, protest, abatement or other contest, including the selection of counsel and compromise or settlement of the claim, but Transmission Owner shall keep Interconnection Customer informed, shall consider in good faith suggestions from Interconnection Customer about the conduct of the contest, and shall reasonably permit Interconnection Customer or an Interconnection Customer representative to attend contest proceedings.

Interconnection Customer shall pay to Transmission Owner on a periodic basis, as invoiced by Transmission Owner, Transmission Owner’s documented reasonable costs of prosecuting such appeal, protest, abatement or other contest. At any time during the contest, Transmission Owner may agree to a settlement either with Interconnection Customer's consent or after obtaining written advice from nationally-recognized tax counsel, selected by Transmission Owner, but reasonably acceptable to Interconnection Customer, that the proposed settlement represents a reasonable settlement given the hazards of litigation. Interconnection Customer's obligation shall be based on the amount of the settlement agreed to by Interconnection Customer, or if a higher amount, so much of the settlement that is supported by the written advice from nationally-recognized tax counsel selected under the terms of the preceding sentence. The settlement amount shall be calculated on a fully grossed-up basis to cover any related cost consequences of the current tax liability. Any settlement without Interconnection Customer's consent or such written advice will relieve Interconnection Customer from any obligation to indemnify Transmission Owner for the tax at issue in the contest.

5.17.8 Refund. In the event that (a) a private letter ruling is issued to Transmission Owner which holds that any amount paid or the value of any property transferred by Interconnection Customer to Transmission Owner under the terms of this LGIA is not subject to federal income taxation, (b) any legislative change or administrative announcement, notice, ruling or other determination makes it reasonably clear to Transmission Owner in good faith that any amount paid or

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the value of any property transferred by Interconnection Customer to Transmission Owner under the terms of this LGIA is not taxable to Transmission Owner, (c) any abatement, appeal, protest, or other contest results in a determination that any payments or transfers made by Interconnection Customer to Transmission Owner are not subject to federal income tax, or (d) if Transmission Owner receives a refund from any taxing authority for any overpayment of tax attributable to any payment or property transfer made by Interconnection Customer to Transmission Owner pursuant to this LGIA, Transmission Owner shall promptly refund to Interconnection Customer the following:

(i) any payment made by Interconnection Customer under this Article 5.17 for taxes that is attributable to the amount determined to be non-taxable, together with interest thereon,

(ii) interest on any amounts paid by Interconnection Customer to Transmission Owner for such taxes which Transmission Owner did not submit to the taxing authority, calculated in accordance with the methodology set forth in 18 C.F.R. Section 35.19a(a)(2)(iii) from the date payment was made by Interconnection Customer to the date Transmission Owner refunds such payment to Interconnection Customer, and

(iii) with respect to any such taxes paid by Transmission Owner, any refund or credit Transmission Owner receives or to which it may be entitled from any Governmental Authority, interest (or that portion thereof attributable to the payment described in clause (i), above) owed to the Transmission Owner for such overpayment of taxes (including any reduction in interest otherwise payable by Transmission Owner to any Governmental Authority resulting from an offset or credit); provided, however, that Transmission Owner will remit such amount promptly to Interconnection Customer only after and to the extent that Transmission Owner has received a tax refund, credit or offset from any Governmental Authority for any applicable overpayment of income tax related to the Transmission Owner’s Interconnection Facilities. The intent of this provision is to leave both parties, to the extent practicable, in the event that no taxes are due with respect to any payment for Interconnection Facilities and Network Upgrades hereunder, in the same position they would have been in had no such tax payments been made.

5.17.9 Taxes Other Than Income Taxes. Upon the timely request by Interconnection Customer, and at Interconnection Customer’s sole expense, Transmission Owner shall appeal, protest, seek abatement of, or otherwise contest any tax (other than federal or state income tax) asserted or assessed against Transmission Owner for which Interconnection Customer may be required to reimburse Transmission Owner under the terms of this LGIA. Interconnection Customer shall pay to Transmission Owner on a periodic basis, as invoiced by Transmission Owner, Transmission Owner’s documented reasonable costs of prosecuting such appeal, protest, abatement, or other contest. Interconnection Customer and Transmission Owner shall cooperate in good faith with respect to

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any such contest. Unless the payment of such taxes is a prerequisite to an appeal or abatement or cannot be deferred, no amount shall be payable by Interconnection Customer to Transmission Owner for such taxes until they are assessed by a final, non-appealable order by any court or agency of competent jurisdiction. In the event that a tax payment is withheld and ultimately due and payable after appeal, Interconnection Customer will be responsible for all taxes, interest and penalties, other than penalties attributable to any delay caused by Transmission Owner.

5.18 Tax Status. Each Party shall cooperate with the other Parties to maintain each Party’s tax status. Nothing in this LGIA is intended to adversely affect any Party’s tax-exempt status with respect to the issuance of bonds including, but not limited to, Local Furnishing Bonds.

5.19 Modification.

5.19.1 General. Either Party may undertake modifications to its facilities. If a Party plans to undertake a modification that reasonably may be expected to affect another Party's facilities, that Party shall provide to the other Parties sufficient information regarding such modification so that the other Parties may evaluate the potential impact of such modification prior to commencement of the work. Such information shall be deemed to be Confidential Information hereunder and shall include information concerning the timing of such modifications and whether such modifications are expected to interrupt the flow of electricity from the Generating Facility. The Party desiring to perform such work shall provide the relevant drawings, plans, and specifications to the other Parties at least ninety (90) Calendar Days in advance of the commencement of the work or such shorter period upon which the Parties may agree, which agreement shall not unreasonably be withheld, conditioned or delayed.

In the case of Generating Facility modifications that do not require Interconnection Customer to submit an Interconnection Request, Transmission Provider shall provide, within thirty (30) Calendar Days (or such other time as the Parties may agree), an estimate of any additional modifications to the Transmission or Distribution System as applicable, Transmission Owner’s Interconnection Facilities, Network Upgrades, Transmission Owner’s System Protection Facilities, and/or Distribution Upgrades necessitated by such Interconnection Customer modification and a good faith estimate of the costs thereof.

5.19.2 Standards. Any additions, modifications, or replacements made to a Party’s facilities shall be designed, constructed and operated in accordance with this LGIA and Good Utility Practice.

5.19.3 Modification Costs. Interconnection Customer shall not be directly assigned the costs of any additions, modifications, or replacements that Transmission Owner makes to the Transmission Owner’s Interconnection Facilities, Network Upgrades, Transmission Owner’s System Protection Facilities, Distribution Upgrades, or the Transmission or Distribution System, as applicable, to facilitate the interconnection of a third party to the Transmission Owner’s Interconnection Facilities or the Transmission or Distribution System, as applicable, or to provide

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transmission service to a third party under the Tariff. Interconnection Customer shall be responsible for the costs of any additions, modifications, or replacements to the Interconnection Customer’s Interconnection Facilities that may be necessary to maintain or upgrade such Interconnection Customer’s Interconnection Facilities consistent with Applicable Laws and Regulations, Applicable Reliability Standards or Good Utility Practice.

ARTICLE 6. TESTING AND INSPECTION

6.1 Pre-Commercial Operation Date Testing and Modifications. Prior to the Commercial Operation Date, the Transmission Owner shall test the Transmission Owner’s Interconnection Facilities, Network Upgrades, Transmission Owner’s System Protection Facilities, and Distribution Upgrades, and Interconnection Customer shall test each electric production device at the Generating Facility, Interconnection Customer’s System Protection Facilities, and the Interconnection Customer’s Interconnection Facilities to ensure their safe and reliable operation. Similar testing may be required after initial operation. Transmission Owner and Interconnection Customer shall make any modifications to their respective facilities that are found to be necessary as a result of such testing. Interconnection Customer shall bear the cost of all such testing and modifications. Interconnection Customer shall generate test energy at the Generating Facility only if it has arranged for the delivery of such test energy.

6.2 Post-Commercial Operation Date Testing and Modifications. Each Party shall at its own expense perform routine inspection and testing of its facilities and equipment in accordance with Good Utility Practice as may be necessary to ensure the continued interconnection of the Generating Facility with the Transmission or Distribution System, as applicable, in a safe and reliable manner. Each Party shall have the right, upon advance written notice, to require reasonable additional testing of the Interconnection Facilities, at the requesting Party’s expense, as may be in accordance with Good Utility Practice.

6.3 Right to Observe Testing. Each Party shall notify the other Parties in advance of its performance of tests of its Interconnection Facilities. The other Parties shall each have the right, at its own expense, to observe such testing.

6.4 Right to Inspect. Each Party shall have the right, but shall have no obligation to: (i) observe Transmission Owner’s and Interconnection Customer’s tests and/or inspection of any of their respective System Protection Facilities and other protective equipment, including power system stabilizers; (ii) review the settings of the System Protection Facilities and other protective equipment; and (iii) review the maintenance records relative to the Interconnection Facilities, the System Protection Facilities and other protective equipment. A Party may exercise these rights from time to time as it deems necessary upon reasonable notice to the other Parties. The exercise or non-exercise by a Party of any such rights shall not be construed as an endorsement or confirmation of any element or condition of the Interconnection Facilities or the System Protection Facilities or other protective equipment or the operation thereof, or as a warranty as to the fitness, safety, desirability, or reliability of same. Any information that a Party obtains through the exercise of any of its rights under this Article 6.4 shall be deemed to be Confidential Information and treated pursuant to Article 22 of this LGIA.

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ARTICLE 7. METERING

7.1 General. Each Party shall comply with the Applicable Reliability Council requirements. Unless otherwise agreed by the Parties, Transmission Owner, at its election, or otherwise the Interconnection Customer, shall install Metering Equipment (the “Metering Party”) at the Point of Interconnection prior to any operation of the Generating Facility and Transmission Owner, at its election, or otherwise the Interconnection Customer shall own, operate, test, and maintain such Metering Equipment. Power flows to and from the Generating Facility shall be measured at or, at the Metering Party’s option, compensated to, the Point of Interconnection. The Metering Party shall provide metering quantities, in analog and/or digital form, to the other Parties upon request. Interconnection Customer shall bear all reasonable documented costs associated with the purchase, installation, operation, testing and maintenance of the Metering Equipment.

7.2 Check Meters. Interconnection Customer, at its option and expense, may install and operate, on its premises and on its side of the Point of Interconnection, one or more check meters to check the Metering Equipment owned by the Metering Party. Such check meters shall be for check purposes only and shall not be used for the measurement of power flows for purposes of this LGIA, except as provided in Article 7.4 below. The check meters shall be subject at all reasonable times to inspection and examination by Transmission Provider, Transmission Owner or their designees. The installation, operation and maintenance thereof shall be performed entirely by Interconnection Customer in accordance with Good Utility Practice.

7.3 Standards. The Metering Party shall install, calibrate, and test revenue quality Metering Equipment in accordance with applicable ANSI standards.

7.4 Testing of Metering Equipment. The Metering Party shall inspect and test Metering Equipment upon installation and at least once every two (2) years thereafter. If requested to do so by a Party, the Metering Party shall, at the requesting Party’s expense, inspect or test Metering Equipment more frequently than every two (2) years. The Metering Party shall give reasonable notice to the other Parties of the time when any inspection or test shall take place, and the other Parties may have representatives present at the test or inspection. If at any time Metering Equipment is found to be inaccurate or defective, it shall be adjusted, repaired, or replaced at Interconnection Customer's expense, in order to provide accurate metering, unless the inaccuracy or defect is due to the Metering Party’s failure to maintain, then the Metering Party shall pay. If Metering Equipment fails to register, or if the measurement made by Metering Equipment during a test varies by more than two percent (2%) from the measurement made by the standard meter used in the test, the Metering Party shall adjust the measurements by correcting all measurements for the period during which Metering Equipment was in error by using Interconnection Customer’s check meters, if installed. If no such check meters are installed or if the period cannot be reasonably ascertained, the adjustment shall be for the period immediately preceding the test of the Metering Equipment equal to one-half the time from the date of the previous test of the Metering Equipment.

7.5 Metering Data. At Interconnection Customer's expense, the metered data shall be telemetered to one or more locations designated by Transmission Provider and Transmission Owner and one or more locations designated by Interconnection Customer.

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Such telemetered data shall be used, under normal operating conditions, as the official measurement of the amount of energy delivered from the Generating Facility to the Point of Interconnection.

ARTICLE 8. COMMUNICATIONS

8.1 Interconnection Customer Obligations. Interconnection Customer shall maintain satisfactory operating communications with Transmission Provider's Transmission System dispatcher or representative designated by Transmission Provider. Interconnection Customer shall provide standard voice line, dedicated voice line, and facsimile communications at its Generating Facility control room or central dispatch facility through use of either the public telephone system or a voice communications system that does not rely on the public telephone system. Interconnection Customer shall also provide the dedicated data circuit(s) necessary to provide Interconnection Customer data to Transmission Provider as set forth in Appendix D, Security Arrangements Details. The data circuit(s) shall extend from the Generating Facility to the location(s) specified by Transmission Provider. Any required maintenance of such communications equipment shall be performed by and at the cost of Interconnection Customer. Operational communications shall be activated and maintained under, but not be limited to, the following events: system paralleling or separation, scheduled and unscheduled shutdowns, equipment clearances, and hourly and daily load data.

8.2 Remote Terminal Unit. Prior to the Initial Synchronization Date of the Generating Facility, a Remote Terminal Unit, or equivalent data collection and transfer equipment acceptable to both Parties, shall be installed by Interconnection Customer, or by Transmission Owner at Interconnection Customer's expense, to gather accumulated and instantaneous data to be telemetered to the location(s) designated by Transmission Owner and Transmission Provider through use of a dedicated point-to-point data circuit(s) as indicated in Article 8.1. The communication protocol for the data circuit(s) shall be specified by Transmission Owner and Transmission Provider. Instantaneous bi-directional analog real power and reactive power flow information must be telemetered directly to the location(s) specified by Transmission Provider and Transmission Owner.

Each Party will promptly advise the other Parties if it detects or otherwise learns of any metering, telemetry or communications equipment errors or malfunctions that require the attention and/or correction. The Party owning such equipment shall correct such error or malfunction as soon as reasonably feasible.

8.3 No Annexation. Any and all equipment placed on the premises of a Party shall be and remain the property of the Party providing such equipment regardless of the mode and manner of annexation or attachment to real property, unless otherwise mutually agreed by the Parties.

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ARTICLE 9. OPERATIONS

9.1 General. Each Party shall comply with the Applicable Reliability Council requirements. Each Party shall provide to any Party all information that may reasonably be required by that Party to comply with Applicable Laws and Regulations and Applicable Reliability Standards.

9.2 Control Area Notification. At least three months before Initial Synchronization Date, the Interconnection Customer shall notify the Transmission Provider and Transmission Owner in writing of the Control Area in which the Generating Facility will be located. If the Interconnection Customer elects to locate the Generating Facility through dynamic metering/scheduling in a Control Area other than the Control Area in which the Generating Facility is physically located, and if permitted to do so by the relevant transmission tariffs, all necessary arrangements, including but not limited to those set forth in Article 7 and Article 8 of this LGIA, and remote Control Area generator interchange agreements, if applicable, and the appropriate measures under such agreements, shall be executed and implemented prior to the placement of the Generating Facility in the other Control Area.

9.3 Transmission Provider and Transmission Owner Obligations. Transmission Provider shall cause the Transmission System and the Transmission Owner’s Interconnection Facilities to be operated, maintained, and controlled in a safe and reliable manner in accordance with this LGIA. Transmission Provider, or its designee, may provide operating instructions to Interconnection Customer consistent with this LGIA and Transmission Provider’s and, if applicable, Transmission Owner’s operating protocols and procedures as they may change from time to time. Transmission Provider will consider changes to its operating protocols and procedures proposed by Interconnection Customer.

9.4 Interconnection Customer Obligations. Interconnection Customer shall at its own expense operate, maintain and control the Generating Facility and the Interconnection Customer’s Interconnection Facilities in a safe and reliable manner and in accordance with this LGIA. The Generating Facility must be operated in accordance with the operating limits, if any, in the Interconnection Facilities Study and specified in Appendix C of this LGIA. Interconnection Customer shall operate the Generating Facility and the Interconnection Customer’s Interconnection Facilities in accordance with all applicable requirements of the Transmission Provider or its designated Control Area Operator of which the Generating Facility is part, as such requirements are set forth in Appendix C, Interconnection Details, of this LGIA. Appendix C, Interconnection Details, will be modified to reflect changes to the requirements as they may change from time to time. Any Party may request that a Party provide copies of the requirements set forth in Appendix C, Interconnection Details, of this LGIA.

9.5 Start-Up and Synchronization. Consistent with the Parties’ mutually acceptable procedures, the Interconnection Customer is responsible for the proper synchronization of the Generating Facility to the Transmission or Distribution System, as applicable.

9.6Reactive Power.

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9.6.1 Power Factor Design Criteria. Interconnection Customer shall design the Generating Facility to be capable of maintaining a composite power delivery at continuous rated power output at the Point of Interconnection at all power factors over 0.95 leading to 0.95 lagging, unless Transmission Provider has established different requirements that apply to all generators in the Control Area on a comparable basis. The applicable Control Area power factor requirements are listed on the Transmission Provider’s website at https://www.misoenergy.org/Library/Repository/Study/Generator%20Interconnection/Reactive%20Generator%20Requirements.pdf and may be referenced in the Appendices to this LGIA. The Generating Facility shall be capable of continuous dynamic operation throughout the power factor design range as measured at the Point of Interconnection. Such operation shall account for the net effect of all energy production devices on the Interconnection Customer’s side of the Point of Interconnection. The requirements of this Article 9.6.1 shall not apply to wind generators.

9.6.2 Voltage Schedules. Once the Interconnection Customer has synchronized the Generating Facility with the Transmission System, Transmission Provider shall require Interconnection Customer to operate the Generating Facility to produce or absorb reactive power within the design limitations of the Generating Facility set forth in Article 9.6.1 (Power Factor Design Criteria), to maintain the output voltage or power factor at the Point of Interconnection as specified by the Transmission Provider. Transmission Provider’s voltage schedules shall treat all sources of reactive power in the Control Area in an equitable and not unduly discriminatory manner. Transmission Provider shall exercise Reasonable Efforts to provide Interconnection Customer with such schedules at least one (1) day in advance, and may make changes to such schedules as necessary to maintain the reliability of the Transmission or Distribution System as applicable. Interconnection Customer shall operate the Generating Facility to maintain the specified output voltage or power factor at the Point of Interconnection within the design limitations of the Generating Facility set forth in Article 9.6.1 (Power Factor Design Criteria). If Interconnection Customer is unable to maintain the specified voltage or power factor, it shall promptly notify Transmission Provider’s system operator, or its designated representative.

9.6.2.1 Governors and Regulators. Whenever the Generating Facility is operated in parallel with the Transmission or Distribution System as applicable and the speed governors (if installed on the generating unit pursuant to Good Utility Practice) and voltage regulators are capable of operation, Interconnection Customer shall operate the Generating Facility with its speed governors and voltage regulators in automatic operation. If the Generating Facility’s speed governors and voltage regulators are not capable of such automatic operation, the Interconnection Customer shall immediately notify Transmission Provider’s system operator, or its designated representative, and ensure that such Generating Facility’s reactive power production or absorption (measured in MVARs) are within the

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design capability of the Generating Facility’s generating unit(s) and steady state stability limits. Interconnection Customer shall not cause its Generating Facility to disconnect automatically or instantaneously from the Transmission or Distribution System, as applicable, or trip any generating unit

comprising the Generating Facility for an under or over frequency condition unless the abnormal frequency condition persists for a time period beyond the limits set forth in ANSI/IEEE Standard C37.106, or such other standard as applied to other generators in the Control Area on a comparable basis.

9.6.3 Payment for Reactive Power. Payments for reactive power shall be pursuant to any tariff or rate schedule filed by the Transmission Provider and approved by the FERC.

9.7Outages and Interruptions.

9.7.1 Outages.

9.7.1.1 Outage Authority and Coordination. Interconnection Customer and Transmission Owner may each in accordance with Good Utility Practice in coordination with the other Party and Transmission Provider remove from service any of its respective Interconnection Facilities, System Protection Facilities, Network Upgrades, System Protection Facilities or Distribution Upgrades that may impact the other Party's facilities as necessary to perform maintenance or testing or to install or replace equipment. Absent an Emergency Condition, the Party scheduling a removal of such facility(ies) from service will use Reasonable Efforts to notify one another and schedule such removal on a date and time mutually acceptable to the Parties. In all circumstances, any Party planning to remove such facility(ies) from service shall use Reasonable Efforts to minimize the effect on the other Parties of such removal.

9.7.1.2 Outage Schedules. The Transmission Provider shall post scheduled outages of transmission facilities on the OASIS. Interconnection Customer shall submit its planned maintenance schedules for the Generating Facility to Transmission Provider and Transmission Owner for a minimum of a rolling twenty-four month period in accordance with the Transmission Provider’s procedures. Interconnection Customer shall update its planned maintenance schedules as necessary. Transmission Provider may request Interconnection Customer to reschedule its maintenance as necessary to maintain the reliability of the Transmission System; provided, however, adequacy of generation supply shall not be a criterion in determining Transmission System reliability. Transmission Provider shall compensate, pursuant to applicable Transmission Provider tariff or rate schedule, Interconnection Customer for any additional direct costs that the Interconnection Customer incurs as a result of having to reschedule maintenance, including any additional overtime, breaking of maintenance contracts or other costs above and beyond the cost the Interconnection Customer would have incurred absent the Transmission

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Provider’s request to reschedule maintenance. Interconnection Customer will not be eligible to receive compensation, if during the twelve (12) months prior to the date of the scheduled maintenance, the Interconnection Customer had modified its schedule of maintenance activities.

Costs shall be determined by negotiation between the Transmission Provider and Interconnection Customer prior to implementation of the voluntary change in outage schedules, or if such request is made by or on behalf of a Transmission Customer requesting firm service, costs and recovery of costs shall be determined through a bilateral agreement between the Transmission Customer and the Interconnection Customer. Voluntary changes to outage schedules under this Article 9.7.1.2 are separate from actions and compensation required under Article 13 and for which costs are recovered in accordance with Transmission Provider’s applicable tariff or rate schedule.

9.7.1.3 Outage Restoration. If an outage on either the Interconnection Customer’s or Transmission Owner’s Interconnection Facilities, Network Upgrades, System Protection Facilities or Distribution Upgrades adversely affects a Party's operations or facilities, the Party that owns or controls the facility that is out of service shall use Reasonable Efforts to promptly restore such facility(ies) to a normal operating condition consistent with the nature of the outage. The Party that owns or controls the facility that is out of service shall provide the other Parties, to the extent such information is known, information on the nature of the Emergency Condition, an estimated time of restoration, and any corrective actions required. Initial verbal notice shall be followed up as soon as practicable with written notice to the other Parties explaining the nature of the outage.

9.7.2 Interruption of Service. If required by Good Utility Practice to do so, Transmission Provider may require Interconnection Customer to interrupt or reduce deliveries of electricity if such delivery of electricity could adversely affect Transmission Provider’s ability to perform such activities as are necessary to safely and reliably operate and maintain the Transmission System. The following provisions shall apply to any interruption or reduction permitted under this Article 9.7.2:

9.7.2.1 The interruption or reduction shall continue only for so long as reasonably necessary under Good Utility Practice;

9.7.2.2 Any such interruption or reduction shall be made on an equitable, non-discriminatory basis with respect to all generating facilities directly connected to the Transmission or Distribution System, as applicable;

9.7.2.3 When the interruption or reduction must be made under circumstances which do not allow for advance notice, Transmission Provider shall notify Interconnection Customer by telephone as soon as practicable of the reasons for the curtailment, interruption, or reduction, and, if known, its

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expected duration. Telephone notification shall be followed by written notification as soon as practicable;

9.7.2.4 Except during the existence of an Emergency Condition, when the interruption or reduction can be scheduled without advance notice, Transmission Provider shall notify Interconnection Customer in advance regarding the timing of such scheduling and further notify Interconnection Customer of the expected duration. Transmission Provider shall coordinate with the Interconnection Customer using Good Utility Practice to schedule the interruption or reduction during periods of least impact to the Interconnection Customer, Transmission Owner and the Transmission Provider;

9.7.2.5 The Parties shall cooperate and coordinate with each other to the extent necessary in order to restore the Generating Facility, Interconnection Facilities, and the Transmission or Distribution System, as applicable to their normal operating state, consistent with system conditions and Good Utility Practice.

9.7.3 Under-Frequency and Over Frequency Conditions. The Transmission System is designed to automatically activate a load-shed program as required by the Applicable Reliability Council in the event of an under-frequency system disturbance. Interconnection Customer shall implement under-frequency and over-frequency relay set points for the Generating Facility as required by the Applicable Reliability Council to ensure “ride through” capability of the Transmission System. Generating Facility response to frequency deviations of pre-determined magnitudes, both under-frequency and over-frequency deviations, shall be studied and coordinated with the Transmission Provider in accordance with Good Utility Practice. The term "ride through" as used herein shall mean the ability of a Generating Facility to stay connected to and synchronized with the Transmission System during system disturbances within a range of under-frequency and over-frequency conditions, in accordance with Good Utility Practice.

9.7.4 System Protection and Other Control Requirements.

9.7.4.1 System Protection Facilities. Interconnection Customer shall, at its expense, install, operate and maintain its System Protection Facilities as a part of the Generating Facility or the Interconnection Customer’s Interconnection Facilities. Transmission Owner shall install at Interconnection Customer's expense any Transmission Owner’s System Protection Facilities that may be required on the Transmission Owner’s Interconnection Facilities or the Transmission Owner’s transmission or distribution facilities as a result of the interconnection of the Generating Facility and the Interconnection Customer’s Interconnection Facilities.

9.7.4.2 Interconnection Customer’s and Transmission Owner’s System Protection Facilities shall be designed and coordinated with Affected Systems in accordance with Good Utility Practice.

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9.7.4.3 Each Party shall be responsible for protection of its facilities consistent with Good Utility Practice.

9.7.4.4 Each Party’s protective relay design shall incorporate the necessary test switches to perform the tests required in Article 6. The required test switches will be placed such that they allow operation of lockout relays while preventing breaker failure schemes from operating and causing unnecessary breaker operations and/or the tripping of the Generating Facility.

9.7.4.5 Each Party will test, operate and maintain their respective System Protection Facilities in accordance with Good Utility Practice.

9.7.4.6 Prior to the In-Service Date, and again prior to the Commercial Operation Date, Interconnection Customer or Transmission Owner, or their respective agents, shall perform a complete calibration test and functional trip test of the System Protection Facilities. At intervals suggested by Good Utility Practice and following any apparent malfunction of the System Protection Facilities, Interconnection Customer or Transmission Owner shall each perform both calibration and functional trip tests of their respective System Protection Facilities. These tests do not require the tripping of any in-service generating unit. These tests do, however, require that all protective relays and lockout contacts be activated.

9.7.5 Requirements for Protection. In compliance with Good Utility Practice, Interconnection Customer shall provide, install, own, and maintain relays, circuit breakers and all other devices necessary to remove any fault contribution of the Generating Facility to any short circuit occurring on the Transmission or Distribution System, as applicable, not otherwise isolated by Transmission Owner’s equipment, such that the removal of the fault contribution shall be coordinated with the protective requirements of the Transmission or Distribution System, as applicable. Such protective equipment shall include, without limitation, a disconnecting device or switch with load-interrupting capability located between the Generating Facility and the Transmission or Distribution System, as applicable, at a site selected upon mutual agreement (not to be unreasonably withheld, conditioned or delayed) of the Parties. Interconnection Customer shall be responsible for protection of the Generating Facility and Interconnection Customer's other equipment from such conditions as negative sequence currents, over- or under-frequency, sudden load rejection, over- or under-voltage, and generator loss-of-field. Interconnection Customer shall be solely responsible to disconnect the Generating Facility and Interconnection Customer's other equipment if conditions on the Transmission or Distribution System, as applicable, could adversely affect the Generating Facility.

9.7.6 Power Quality. Neither Party’s facilities shall cause excessive voltage flicker nor introduce excessive distortion to the sinusoidal voltage or current waves as defined by ANSI Standard C84.1-1989, in accordance with IEEE Standard 519, or any applicable superseding electric industry standard. In the event of a conflict between ANSI Standard C84.1-1989, and any applicable superseding electric

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industry standard, the applicable superseding electric industry standard shall control.

9.8 Switching and Tagging Rules. Prior to the Initial Synchronization Date, each Party shall provide the other Parties a copy of its switching and tagging rules that are applicable to the other Parties’ activities. Such switching and tagging rules shall be developed on a non-discriminatory basis. The Parties shall comply with applicable switching and tagging rules, as amended from time to time, in obtaining clearances for work or for switching operations on equipment.

9.9 Use of Interconnection Facilities by Other Parties.

9.9.1 Purpose of Interconnection Facilities. Except as may be required by Applicable Laws and Regulations, or as otherwise agreed to among the Parties, the Interconnection Facilities shall be constructed for the sole purpose of interconnecting the Generating Facility to the Transmission or Distribution System, as applicable, and shall be used for no other purpose.

9.9.2 Other Users. If required by Applicable Laws and Regulations or if the Parties mutually agree, such agreement not to be unreasonably withheld or delayed, to allow one or more parties to use the Transmission Owner's Interconnection Facilities, or any part thereof, Interconnection Customer will be entitled to compensation for the capital expenses it incurred in connection with the Interconnection Facilities based upon the pro rata use of the Interconnection Facilities by Transmission Owner, all non-party users, and Interconnection Customer, in accordance with Applicable Laws and Regulations or upon some other mutually-agreed upon methodology. In addition, cost responsibility for ongoing costs, including operation and maintenance costs associated with the Interconnection Facilities, will be allocated between Interconnection Customer and any non-party users based upon the pro rata use of the Interconnection Facilities by Transmission Owner, all non-party users, and Interconnection Customer, in accordance with Applicable Laws and Regulations or upon some other mutually agreed upon methodology. If the issue of such compensation or allocation cannot be resolved through such negotiations, it shall be submitted to Dispute Resolution pursuant to Section 12 of the Tariff.

9.10 Disturbance Analysis Data Exchange. The Parties will cooperate with one another in the analysis of disturbances to either the Generating Facility or the Transmission System by gathering and providing access to any information relating to any disturbance, including information from oscillography, protective relay targets, breaker operations and sequence of events records, and any disturbance information required by Good Utility Practice.

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ARTICLE 10. MAINTENANCE

10.1 Transmission Owner Obligations. Transmission Owner shall maintain the Transmission Owner’s Interconnection Facilities in a safe and reliable manner and in accordance with this LGIA and all Applicable Laws and Regulations.

10.2 Interconnection Customer Obligations. Interconnection Customer shall maintain the Generating Facility and the Interconnection Customer’s Interconnection Facilities in a safe and reliable manner and in accordance with this LGIA and all Applicable Laws and Regulations.

10.3 Coordination. The Parties shall confer regularly to coordinate the planning, scheduling, and performance of preventive and corrective maintenance on the Generating Facility and the Interconnection Facilities.

10.4 Secondary Systems. Each Party shall cooperate with the other in the inspection, maintenance, and testing of control or power circuits that operate below 600 volts, AC or DC, including, but not limited to, any hardware, control or protective devices, cables, conductors, electric raceways, secondary equipment panels, transducers, batteries, chargers, and voltage and current transformers that directly affect the operation of a Party's facilities and equipment which may reasonably be expected to impact another Party. Each Party shall provide advance notice to the other Parties before undertaking any work on such circuits, especially on electrical circuits involving circuit breaker trip and close contacts, current transformers, or potential transformers.

10.5 Operating and Maintenance Expenses. Subject to the provisions herein addressing the use of facilities by others, and except for operations and maintenance expenses associated with modifications made for providing interconnection or transmission service to a non-party and such non-party pays for such expenses, Interconnection Customer shall be responsible for all reasonable expenses including overheads, associated with: (1) owning, operating, maintaining, repairing, and replacing Interconnection Customer’s Interconnection Facilities; and (2) operation, maintenance, repair and replacement of Transmission Owner’s Interconnection Facilities to the extent required by the Transmission Owner on a comparable basis.

ARTICLE 11. PERFORMANCE OBLIGATION

11.1 Interconnection Customer’s Interconnection Facilities. Interconnection Customer shall design, procure, construct, install, own and/or control the Interconnection Customer’s Interconnection Facilities described in Appendix A at its sole expense.

11.2 Transmission Owner's Interconnection Facilities. Transmission Owner shall design, procure, construct, install, own and/or control the Transmission Owner’s Interconnection Facilities described in Appendix A at the sole expense of the Interconnection Customer.

11.3 Network Upgrades, System Protection Facilities and Distribution Upgrades. Transmission Owner shall design, procure, construct, install, and own the Network Upgrades, Transmission Owner’s System Protection Facilities and Distribution Upgrades

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described in Appendix A. The Interconnection Customer shall be responsible for all costs related to Distribution Upgrades and/or Generator Upgrades. Transmission Owner shall provide the Transmission Provider and Interconnection Customer with written notice pursuant to Article 15 if the Transmission Owner elects to fund the capital for the Network Upgrades and Transmission Owner’s System Protection Facilities; otherwise, such facilities, if any, shall be solely funded by the Interconnection Customer.

11.3.1 Contingencies Affecting Network Upgrades, System Protection Facilities and Distribution Upgrades. Network Upgrades, System Protection Facilities and Distribution Upgrades that are required to accommodate the Generating Facility may be modified because (1) a higher queued interconnection request withdrew or was deemed to have withdrawn, (2) the interconnection agreement associated with a higher queued interconnection request was terminated prior to the project’s In‑Service Date, (3) the Commercial Operation Date for a higher queued interconnection request is delayed such that facilities required to accommodate lower queued projects may be altered, (4) the queue position is reinstated for a higher-queued interconnection request whose queue position was subject to dispute resolution, (5) changes occur in Transmission Provider or Transmission Owner equipment design standards or reliability criteria giving rise to the need for restudy, or (6) the facilities required to accommodate a higher queued interconnection request were modified constituting a Material Modification pursuant to Section 4.4 of the LGIP. The higher queued interconnection requests that could impact the Network Upgrades, System Protection Facilities and Distribution Upgrades required to accommodate the Generating Facility, and possible Modifications that may result from the above listed events affecting the higher queued interconnection requests, to the extent such modifications are reasonably known and can be determined, and estimates of the costs associated with such required Network Upgrades, System Protection Facilities and Distribution Upgrades, are provided in Appendix A.

11.3.2 Agreement to Restudy. The Interconnection Customer agrees to enter into either an Interconnection System Impact Study Agreement or Interconnection Facilities Study Agreement, or both, if at any time before the Network Upgrades, System Protection Facilities and/or Distribution Upgrades associated with higher queued interconnection requests are completed, the Transmission Provider determines restudy is required because one of the contingencies in Article 11.3.1 occurred, and provides notice to Interconnection Customer. Any restudy shall be performed, as applicable, in accordance with Sections 6.4, 7.6 and 8.5 of the LGIP. The Parties agree to amend Appendix A to this LGIA in accordance with Article 30.10 to reflect the results of any restudy required under this Article 11.3.2.

11.4    Transmission Credits.

11.4.1 Repayment of Amounts Advanced for Network Upgrades. Interconnection Customer shall be entitled to a cash repayment by the Transmission Owner(s) and the Affected System Owner(s) that own the Network Upgrades, of the amount paid respectively to Transmission Owner and Affected System Operator, if any, for the Network Upgrades, as provided under Attachment FF of this Tariff

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and including any tax gross-up or other tax-related payments associated with the repayable portion of the Network Upgrades, and not repaid to Interconnection Customer pursuant to Article 5.17.8 or otherwise, to be paid to Interconnection Customer on a dollar-for-dollar basis for the non-usage sensitive portion of transmission charges, as payments are made under the Tariff and Affected System's Tariff for transmission services with respect to the Large Generating Facility. Any repayment shall include interest calculated in accordance with the methodology set forth in FERC’s regulations at 18 C.F.R. § 35.19 (a)(2)(iii) from the date of any payment for Network Upgrades through the date on which the Interconnection Customer receives a repayment of such payment pursuant to this subparagraph. Interest shall not accrue during periods in which the Interconnection Customer has suspended construction pursuant to Article 11 or the Network Upgrades have been determined not to be needed pursuant to this Article 11.4.1. Interconnection Customer may assign such repayment rights to any person.

If the Generating Facility is designated a Network Resource under the Tariff, or if there are otherwise no incremental payments for Transmission Service resulting from the use of the Generating Facility by Transmission Customer, and in the absence of another mutually agreeable payment schedule any repayments provided under Attachment FF shall be established equal to the applicable rate for Firm Point-To-Point Transmission Service for the pricing zone where the Network Load is located multiplied by the portion of the demonstrated output of the Generating Facility designated as a Network Resource by the Network Customer(s) or in the absence of such designation, equal to the monthly firm single system-wide rate defined under Schedule 7 multiplied by the portion of the demonstrated output of the Generating Facility under contract to Network Customer(s) and consistent with studies pursuant to Section 3.2.2.2 of the LGIP.

Notwithstanding the foregoing, as applicable and consistent with the provisions of Attachment FF of this Tariff, Interconnection Customer, Transmission Provider, Transmission Owner, and Affected System Operator may adopt any alternative payment schedule that is mutually agreeable so long as Transmission Owner and Affected System Operator take one of the following actions no later than five (5) years from the Commercial Operation Date: (1) return to Interconnection Customer any amounts advanced for Network Upgrades not previously repaid, or (2) declare in writing that Transmission Owner or Affected System Operator will continue to provide payments to Interconnection Customer on a dollar-for-dollar basis for the non-usage sensitive portion of transmission charges, or develop an alternative schedule that is mutually agreeable and provides for the return of all amounts advanced for Network Upgrades not previously repaid; however, full reimbursement shall not extend beyond twenty (20) years from the Commercial Operation Date. If the Generating Facility fails to achieve commercial operation, but it or another generating facility is later constructed and makes use of the Network Upgrades, Transmission Owner and Affected System Operator shall at that time reimburse Interconnection Customer for the remaining applicable amounts that may be refundable pursuant to Attachment FF of this Tariff that were advanced for the Network Upgrades on their respective systems as described above. Before any such reimbursement can occur, the

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Interconnection Customer, or the entity that ultimately constructs the Generating Facility, if different, is responsible for identifying the entity to which the reimbursement must be made.

11.4.2 Special Provisions for the Transmission Provider as an Affected System. When the Transmission Owner's Transmission or Distribution System (including for this Article 11.4.2 independent distribution systems connected to the Transmission System) is an Affected System for an interconnection in another electric system, the Transmission Provider will coordinate the performance of Interconnection Studies with the other system. The Transmission Provider will determine if any Network Upgrades or Distribution Upgrades, which may be required on the Transmission System as a result of the interconnection, would not have been needed but for the interconnection. Unless the Transmission Owner provides, under the interconnection agreement between the Interconnection Customer and the other system, for the repayment of amounts advanced to the Transmission Provider or an impacted transmission-owning member(s) of the Transmission Provider for Network Upgrades, the Interconnection Customer, the Transmission Provider, and the impacted transmission‑owning member(s) shall enter into an agreement that provides for such repayment by transmission owner(s) as directed by the Transmission Provider. The agreement shall specify the terms governing payments to be made by the Interconnection Customer to the Affected System Operator as well as the payment of refunds by the Affected System Operator.

11.4.3 Notwithstanding any other provision of this LGIA, nothing herein shall be construed as relinquishing or foreclosing any rights, including but not limited to firm transmission rights, capacity rights, transmission congestion rights, or transmission credits, that the Interconnection Customer, shall be entitled to, now or in the future under any other agreement or tariff as a result of, or otherwise associated with, the transmission capacity, if any, created by the Network Upgrades, including the right to obtain cash reimbursement or transmission credits for transmission service that is not associated with the Generating Facility.

11.5 Provision of Security. Unless otherwise provided in Appendix B, at least thirty (30) Calendar Days prior to the commencement of the design, procurement, installation, or construction of a discrete portion of an initial element of the Transmission Owner’s Interconnection Facilities, Transmission Owner’s System Protection Facilities, Network Upgrades, Distribution Upgrades or Stand‑Alone Network Upgrades, or at the request of Transmission Owner if regulatory approvals are required for the construction of such facilities, Interconnection Customer shall provide Transmission Owner, at Interconnection Customer's selection, a guarantee, a surety bond, letter of credit or other form of security that is reasonably acceptable to Transmission Owner and is consistent with the Uniform Commercial Code of the jurisdiction identified in Article 14.2.1. Such security for payment shall be in an amount sufficient to cover the applicable costs and cost commitments required of the Party responsible for building the facilities pursuant to the construction schedule developed in Article 12.1 for designing, engineering, seeking regulatory approval from any Governmental Authority, constructing, procuring and installing the applicable portion of Transmission Owner’s Interconnection Facilities, Transmission

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Owner’s System Protection Facilities, Network Upgrades, Distribution Upgrades or Stand‑Alone Network Upgrades and shall be reduced on a dollar-for-dollar basis for payments made to Transmission Owner for these purposes.

In addition:

11.5.1 The guarantee must be made by an entity that meets the creditworthiness requirements of Transmission Owner, and contain terms and conditions that guarantee payment of any amount that may be due from Interconnection Customer, up to an agreed-to maximum amount.

11.5.2 The letter of credit must be issued by a financial institution reasonably acceptable to Transmission Owner and must specify a reasonable expiration date.

11.5.3 The surety bond must be issued by an insurer reasonably acceptable to Transmission Owner and must specify a reasonable expiration date.

11.6 Interconnection Customer Compensation. If Transmission Provider requests or directs Interconnection Customer to provide a service pursuant to Article 13.4 of this LGIA, Transmission Provider shall compensate Interconnection Customer in accordance with any tariff or rate schedule filed by the Transmission Provider and approved by the FERC.

ARTICLE 12. INVOICE

12.1 General. Each Party shall submit to the other Party, on a monthly basis, invoices of amounts due, if any, for the preceding month. Each invoice shall state the month to which the invoice applies and fully describe the services and equipment provided. The Parties may discharge mutual debts and payment obligations due and owing to each other on the same date through netting, in which case all amounts a Party owes to the other Party under this LGIA, including interest payments or credits, shall be netted so that only the net amount remaining due shall be paid by the owing Party.

12.2 Final Invoice. Within six months after completion of the construction of the Transmission Owner’s Interconnection Facilities, Transmission Owner’s System Protection Facilities, Distribution Upgrades and the Network Upgrades, Transmission Owner shall provide an invoice of the final cost of the construction of the Transmission Owner’s Interconnection Facilities, Transmission Owner’s System Protection Facilities, Distribution Upgrades and the Network Upgrades and shall set forth such costs in sufficient detail to enable Interconnection Customer to compare the actual costs with the estimates and to ascertain deviations, if any, from the cost estimates. Transmission Owner shall refund, with interest (calculated in accordance with 18 C.F.R. Section 35.19a(a)(2)(iii), to Interconnection Customer any amount by which the actual payment by Interconnection Customer for estimated costs exceeds the actual costs of construction within thirty (30) Calendar Days of the issuance of such final construction invoice.

12.3 Payment. Invoices shall be rendered to the paying Party at the address specified in Appendix F. The Party receiving the invoice shall pay the invoice within thirty (30) Calendar Days of receipt. All payments shall be made in immediately available funds

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payable to the other Party, or by wire transfer to a bank named and account designated by the invoicing Party. Payment of invoices by a Party will not constitute a waiver of any rights or claims that Party may have under this LGIA.

12.4 Disputes. In the event of a billing dispute among the Parties, Transmission Provider shall continue to provide Interconnection Service under this LGIA as long as Interconnection Customer: (i) continues to make all payments not in dispute; and (ii) pays to Transmission Provider or Transmission Owner or into an independent escrow account the portion of the invoice in dispute, pending resolution of such dispute. If Interconnection Customer fails to meet these two requirements for continuation of service, then Transmission Provider may or, at Transmission Owner’s request upon Interconnection Customer’s failure to pay, Transmission Owner, shall provide notice to Interconnection Customer of a Default pursuant to Article 17. Within thirty (30) Calendar Days after the resolution of the dispute, the Party that owes money to another Party shall pay the amount due with interest calculated in accord with the methodology set forth in 18 C.F.R. § 35.19a(a)(2)(iii).

ARTICLE 13. EMERGENCIES

13.1 Obligations. Each Party shall comply with the Emergency Condition procedures of the Transmission Provider, NERC, the Applicable Reliability Council, and Applicable Laws and Regulations.

13.2 Notice. Transmission Provider or Transmission Owner shall notify the other Parties promptly when it becomes aware of an Emergency Condition that affects the Transmission Owner’s Interconnection Facilities or the Transmission or Distribution System, as applicable, that may reasonably be expected to affect Interconnection Customer's operation of the Generating Facility or the Interconnection Customer's Interconnection Facilities.

Interconnection Customer shall notify Transmission Provider and Transmission Owner, which includes by definition if applicable, the operator of a distribution system, promptly when it becomes aware of an Emergency Condition that affects the Generating Facility or the Interconnection Customer’s Interconnection Facilities that may reasonably be expected to affect the Transmission or Distribution System, as applicable, or the Transmission Owner’s Interconnection Facilities.

To the extent information is known, the notification shall describe the Emergency Condition, the extent of the damage or deficiency, the expected effect on the operation of Interconnection Customer's or Transmission Provider’s or Transmission Owner’s facilities and operations, its anticipated duration and the corrective action taken and/or to be taken. The initial notice shall be followed as soon as practicable with written notice.

13.3 Immediate Action. Unless, in a Party’s reasonable judgment, immediate action is required, the Party exercising such judgment shall notify and obtain the consent of the other Parties, such consent to not be unreasonably withheld, prior to performing any manual switching operations at the Generating Facility or the Interconnection Customer’s Interconnection Facilities in response to an Emergency Condition either declared by the

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Transmission Provider or otherwise regarding the Transmission or Distribution System, as applicable.

13.4 Transmission Provider and Transmission Owner Authority.

13.4.1 General. Transmission Provider or Transmission Owner may take whatever actions or inactions with regard to the Transmission System or the Transmission Owner’s Interconnection Facilities it deems necessary during an Emergency Condition in order to (i) preserve public health and safety, (ii) preserve the reliability of the Transmission System or the Transmission Owner’s Interconnection Facilities, (iii) limit or prevent damage, and (iv) expedite restoration of service.

Transmission Provider or Transmission Owner shall use Reasonable Efforts to minimize the effect of such actions or inactions on the Generating Facility or the Interconnection Customer’s Interconnection Facilities. Transmission Provider or Transmission Owner may, on the basis of technical considerations, require the Generating Facility to mitigate an Emergency Condition by taking actions necessary and limited in scope to remedy the Emergency Condition, including, but not limited to, directing Interconnection Customer to shut-down, start-up, increase or decrease the real or reactive power output of the Generating Facility; implementing a reduction or disconnection pursuant to Article 13.5.2; directing the Interconnection Customer to assist with blackstart (if available) or restoration efforts; or altering the outage schedules of the Generating Facility and the Interconnection Customer’s Interconnection Facilities. Interconnection Customer shall comply with all of Transmission Provider's or Transmission Owner’s operating instructions concerning Generating Facility real power and reactive power output within the manufacturer’s design limitations of the Generating Facility's equipment that is in service and physically available for operation at the time, in compliance with Applicable Laws and Regulations.

13.4.2 Reduction and Disconnection. Transmission Provider or Transmission Owner may reduce Interconnection Service or disconnect the Generating Facility or the

Interconnection Customer’s Interconnection Facilities when such reduction or disconnection is necessary under Good Utility Practice due to Emergency Conditions. These rights are separate and distinct from any right of curtailment of the Transmission Provider pursuant to the Tariff. When the Transmission Provider can schedule the reduction or disconnection in advance, Transmission Provider shall notify Interconnection Customer of the reasons, timing and expected duration of the reduction or disconnection. Transmission Provider shall coordinate with the Interconnection Customer and Transmission Owner using Good Utility Practice to schedule the reduction or disconnection during periods of least impact to the Interconnection Customer, Transmission Owner and the Transmission Provider. Any reduction or disconnection shall continue only for so long as reasonably necessary under Good Utility Practice. The Parties shall cooperate with each other to restore the Generating Facility, the Interconnection Facilities, and the Transmission System to their normal operating state as soon as practicable consistent with Good Utility Practice.

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13.5 Interconnection Customer Authority. Consistent with Good Utility Practice and this LGIA and the LGIP, the Interconnection Customer may take whatever actions or inactions with regard to the Generating Facility or the Interconnection Customer’s Interconnection Facilities during an Emergency Condition in order to (i) preserve public health and safety, (ii) preserve the reliability of the Generating Facility or the Interconnection Customer’s Interconnection Facilities, (iii) limit or prevent damage, and (iv) expedite restoration of service. Interconnection Customer shall use Reasonable Efforts to minimize the effect of such actions or inactions on the Transmission System and the Transmission Owner’s Interconnection Facilities. Transmission Provider and Transmission Owner shall use Reasonable Efforts to assist Interconnection Customer in such actions.

13.6 Limited Liability. Except as otherwise provided in Article 11.6 of this LGIA, no Party shall be liable to the other for any action it takes in responding to an Emergency Condition so long as such action is made in good faith and is consistent with Good Utility Practice.

13.7 Audit. In accordance with Article 25.3, any Party may audit the performance of another Party when that Party declared an Emergency Condition.

ARTICLE 14. REGULATORY REQUIREMENTS AND GOVERNING LAW

14.1 Regulatory Requirements. Each Party’s obligations under this LGIA shall be subject to its receipt of any required approval or certificate from one or more Governmental Authorities in the form and substance satisfactory to the applying Party, or the Party making any required filings with, or providing notice to, such Governmental Authorities, and the expiration of any time period associated therewith. Each Party shall in good faith seek, and if necessary assist the other Party and use its Reasonable Efforts to obtain such other approvals. Nothing in this LGIA shall require Interconnection Customer to take any action that could result in its inability to obtain, or its loss of, status or exemption under the Federal Power Act, the Public Utility Holding Company Act of 1935, as amended, or the Public Utility Regulatory Policies Act of 1978.

14.2Governing Law.

14.2.1 The validity, interpretation and performance of this LGIA and each of its provisions shall be governed by the laws of the state where the Point of Interconnection is located, without regard to its conflicts of law principles.

14.2.2 This LGIA is subject to all Applicable Laws and Regulations.

14.2.3 Each Party expressly reserves the right to seek changes in, appeal, or otherwise contest any laws, orders, rules, or regulations of a Governmental Authority.

ARTICLE 15. NOTICES

15.1 General. Unless otherwise provided in this LGIA, any notice, demand or request required or permitted to be given by any Party to the other Parties and any instrument required or permitted to be tendered or delivered by a Party in writing to the other Parties

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shall be effective when delivered and may be so given, tendered or delivered, by recognized national courier, or by depositing the same with the United States Postal Service with postage prepaid, for delivery by certified or registered mail, addressed to the Party, or personally delivered to the Party, at the address set out in Appendix F, Addresses for Delivery of Notices and Billings.

Either Party may change the notice information in this LGIA by giving five (5) Business Days written notice prior to the effective date of the change.

15.2 Billings and Payments. Billings and payments shall be sent to the addresses set out in Appendix F.

15.3 Alternative Forms of Notice. Any notice or request required or permitted to be given by any Party to the other and not required by this LGIA to be given in writing may be so given by telephone, facsimile or email to the telephone numbers and email addresses set out in Appendix F.

15.4 Operations and Maintenance Notice. Each Party shall notify the other Parties in writing of the identity of the person(s) that it designates as the point(s) of contact with respect to the implementation of Articles 9 and 10.

ARTICLE 16. FORCE MAJEURE

16.1 Force Majeure.

16.1.1 Economic hardship is not considered a Force Majeure event.

16.1.2 A Party shall not be considered to be in Default with respect to any obligation hereunder, (including obligations under Article 4 and 5), other than the obligation to pay money when due, if prevented from fulfilling such obligation by Force Majeure. A Party unable to fulfill any obligation hereunder (other than an obligation to pay money when due) by reason of Force Majeure shall give notice and the full particulars of such Force Majeure to the other Parties in writing or by telephone as soon as reasonably possible after the occurrence of the cause relied upon. Telephone, facsimile or email notices given pursuant to this Article shall be confirmed in writing as soon as reasonably possible and shall specifically state full particulars of the Force Majeure, the time and date when the Force Majeure occurred and when the Force Majeure is reasonably expected to cease. The Party affected shall exercise Reasonable Efforts to remove such disability with reasonable dispatch, but shall not be required to accede or agree to any provision not satisfactory to it in order to settle and terminate a strike or other labor disturbance.

ARTICLE 17. DEFAULT

17.1 Default

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17.1.1 General. No Default shall exist where such failure to discharge an obligation (other than the payment of money) is the result of Force Majeure as defined in this LGIA or the result of an act or omission of another Party. Upon a Breach, the non-Breaching Party or Parties shall give written notice of such Breach to the Breaching Party with a copy to the other Party if one Party gives notice of such Breach. Except as provided in Article 17.1.2, the Breaching Party shall have thirty (30) Calendar Days from receipt of the Breach notice within which to cure such Breach; provided however, if such Breach is not capable of cure within thirty (30) Calendar Days, the Breaching Party shall commence such cure within thirty (30) Calendar Days after notice and continuously and diligently complete such cure within ninety (90) Calendar Days from receipt of the Breach notice; and, if cured within such time, the Breach specified in such notice shall cease to exist.

17.1.2 Right to Terminate. If a Breach is not cured as provided in this Article, or if a Breach is not capable of being cured within the period provided for herein, the non-Breaching Party or Parties shall have the right to terminate this LGIA by written notice to the Breaching Party at any time until cure occurs, with a copy to the other Party if one Party gives notice of such right to terminate, and be relieved of any further obligation hereunder and, whether or not that Party(ies) terminates this LGIA, to recover from the Breaching Party all amounts due hereunder, plus all other damages and remedies to which it is (they are) entitled at law or in equity. The provisions of this Article will survive termination of this LGIA.

ARTICLE 18. Limitation of liability, INDEMNITY, CONSEQUENTIAL DAMAGES, AND INSURANCE

18.1 Limitation of Liability. A Party shall not be liable to another Party or to any third party or other person for any damages arising out of actions under this LGIA, including, but not limited to, any act or omission that results in an interruption, deficiency or imperfection of Interconnection Service, except as provided in this Tariff. The provisions set forth in the Tariff shall be additionally applicable to any Party acting in good faith to implement or comply with its obligations under this LGIA, regardless of whether the obligation is preceded by a specific directive. 

18.2 Indemnity. An Indemnifying Party shall at all times indemnify, defend and hold the other Parties harmless from Loss.

18.2.1 Indemnified Party. If an Indemnified Party is entitled to indemnification under this Article 18 as a result of a claim by a non-party, and the Indemnifying Party fails, after notice and reasonable opportunity to proceed under Article 18.2, to assume the defense of such claim, such Indemnified Party may at the expense of the Indemnifying Party contest, settle or consent to the entry of any judgment with respect to, or pay in full, such claim.

18.2.2 Indemnifying Party. If an Indemnifying Party is obligated to indemnify and hold any Indemnified Party harmless under this Article 18, the amount owing to the Indemnified Party shall be the amount of such Indemnified Party's actual Loss, net of any insurance or other recovery.

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18.2.3 Indemnity Procedures. Promptly after receipt by an Indemnified Party of any claim or notice of the commencement of any action or administrative or legal proceeding or investigation as to which the indemnity provided for in Article 18.2 may apply, the Indemnified Party shall notify the Indemnifying Party of such fact. Any failure of or delay in such notification shall not affect a Party's indemnification obligation unless such failure or delay is materially prejudicial to the Indemnifying Party.

The Indemnifying Party shall have the right to assume the defense thereof with counsel designated by such Indemnifying Party and reasonably satisfactory to the Indemnified Party. If the defendants in any such action include one or more Indemnified Parties and the Indemnifying Party and if the Indemnified Party reasonably concludes that there may be legal defenses available to it and/or other Indemnified Parties which are different from or additional to those available to the Indemnifying Party, the Indemnified Party shall have the right to select separate counsel to assert such legal defenses and to otherwise participate in the defense of such action on its own behalf. In such instances, the Indemnifying Party shall only be required to pay the fees and expenses of one additional attorney to represent an Indemnified Party or Indemnified Parties having such differing or additional legal defenses.

The Indemnified Party shall be entitled, at its expense, to participate in any such action, suit or proceeding, the defense of which has been assumed by the Indemnifying Party. Notwithstanding the foregoing, the Indemnifying Party (i) shall not be entitled to assume and control the defense of any such action, suit or proceedings if and to the extent that, in the opinion of the Indemnified Party and its counsel, such action, suit or proceeding involves the potential imposition of criminal liability on the Indemnified Party, or there exists a conflict or adversity of interest between the Indemnified Party and the Indemnifying Party, in such event the Indemnifying Party shall pay the reasonable expenses of the Indemnified Party, and (ii) shall not settle or consent to the entry of any judgment in any action, suit or proceeding without the consent of the Indemnified Party, which shall not be reasonably withheld, conditioned or delayed.

18.3 Consequential Damages. Other than the Liquidated Damages heretofore described, in no event shall either Party be liable under any provision of this LGIA for any losses, damages, costs, or expenses for any special, indirect, incidental, consequential, or punitive damages including, but not limited to, loss of profit or revenue, loss of the use of equipment, cost of capital, cost of temporary equipment or services, whether based in whole or in part in contract, in tort, including negligence, strict liability, or any other theory of liability; provided; however, that damages for which a Party may be liable to the other Party under another agreement will not be considered to be special, indirect, incidental, or consequential damages hereunder.

18.4 Insurance. Each Party shall, at its own expense, maintain in force throughout the period of this LGIA, and until released by the other Parties, the following minimum insurance coverages, with insurers authorized to do business or an approved surplus lines carrier in the state where the Point of Interconnection is located:

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18.4.1 Employers' Liability and Workers' Compensation Insurance providing statutory benefits in accordance with the laws and regulations of the state in which the Point of Interconnection is located.

18.4.2 Commercial General Liability Insurance including premises and operations, personal injury, broad form property damage, broad form blanket contractual liability coverage (including coverage for the contractual indemnification) products and completed operations coverage, coverage for explosion, collapse and underground hazards, independent contractors coverage, coverage for pollution to the extent normally available and punitive damages to the extent normally available and a cross liability endorsement, with minimum limits of One Million Dollars ($1,000,000) per occurrence/One Million Dollars ($1,000,000) aggregate combined single limit for personal injury, bodily injury, including death and property damage.

18.4.3 Comprehensive Automobile Liability Insurance, for coverage of owned and non‑owned and hired vehicles, trailers or semi‑trailers licensed for travel on public roads, with a minimum combined single limit of One Million Dollars ($1,000,000) each occurrence for bodily injury, including death, and property damage.

18.4.4 Excess Public Liability Insurance over and above the Employer’s Liability, Commercial General Liability and Comprehensive Automobile Liability Insurance coverage, with a minimum combined single limit of Twenty Million Dollars ($20,000,000) per occurrence/Twenty Million Dollars ($20,000,000) aggregate.

18.4.5 The Commercial General Liability Insurance, Comprehensive Automobile Insurance and Excess Public Liability Insurance policies shall name the other Parties, their parents, associated and Affiliate companies and their respective directors, officers, agents, servants and employees ("Other Party Group") as additional insured. All policies shall contain provisions whereby the insurers waive all rights of subrogation in accordance with the provisions of this LGIA against the Other Party Groups and provide thirty (30) Calendar Days’ advance written notice to the Other Party Groups prior to anniversary date of cancellation or any material change in coverage or condition.

18.4.6 The Commercial General Liability Insurance, Comprehensive Automobile Liability Insurance and Excess Public Liability Insurance policies shall contain provisions that specify that the policies are primary and shall apply to such extent without consideration for other policies separately carried and shall state that each insured is provided coverage as though a separate policy had been issued to each, except the insurer’s liability shall not be increased beyond the amount for which the insurer would have been liable had only one insured been covered. Each Party shall be responsible for its respective deductibles or retentions.

18.4.7 The Commercial General Liability Insurance, Comprehensive Automobile Liability Insurance and Excess Public Liability Insurance policies, if written on a Claims First Made Basis, shall be maintained in full force and effect for two (2) years after termination of this LGIA, which coverage may be in the form of tail coverage or extended reporting period coverage if agreed by the Parties.

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18.4.8 The requirements contained herein as to the types and limits of all insurance to be maintained by the Parties are not intended to and shall not in any manner, limit or qualify the liabilities and obligations assumed by the Parties under this LGIA.

18.4.9 Within ten (10) days following execution of this LGIA, and as soon as practicable after the end of each fiscal year or at the renewal of the insurance policy and in any event within ninety (90) days thereafter, each Party shall provide certification of all insurance required in this LGIA, executed by each insurer or by an authorized representative of each insurer.

18.4.10 Notwithstanding the foregoing, each Party may self-insure to meet the minimum insurance requirements of Articles 18.4.1 through 18.4.8, to the extent it maintains a self-insurance program; provided that, such Party’s senior secured debt is rated at investment grade, or better, by Standard & Poor’s and that its self‑insurance program meets minimum insurance requirements under Articles 18.4.1 through 18.4.8. For any period of time that a Party’s senior secured debt is unrated by Standard & Poor’s or is rated at less than investment grade by Standard & Poor’s, such Party shall comply with the insurance requirements applicable to it under Articles 18.4.1 through 18.4.9. In the event that a Party is permitted to self-insure pursuant to this article, it shall notify the other Party that it meets the requirements to self‑insure and that its self‑insurance program meets the minimum insurance requirements in a manner consistent with that specified in Article 18.4.9.

18.4.11 The Parties agree to report to each other in writing as soon as practical all accidents or occurrences resulting in injuries to any person, including death, and any property damage arising out of this LGIA.

ARTICLE 19. ASSIGNMENT

19.1 Assignment. This LGIA may be assigned by any Party only with the written consent of the other Parties; provided that a Party may assign this LGIA without the consent of the other Parties to any Affiliate of the assigning Party with an equal or greater credit rating and with the legal authority and operational ability to satisfy the obligations of the assigning Party under this LGIA; and provided further that the Interconnection Customer shall have the right to assign this LGIA, without the consent of either the Transmission Provider or Transmission Owner, for collateral security purposes to aid in providing financing for the Generating Facility, provided that the Interconnection Customer will promptly notify the Transmission Provider of any such assignment. Any financing arrangement entered into by the Interconnection Customer pursuant to this Article will provide that prior to or upon the exercise of the secured party’s , trustee’s or mortgagee’s assignment rights pursuant to said arrangement, the secured creditor, the trustee or mortgagee will notify the Transmission Provider of the date and particulars of any such exercise of assignment right(s), including providing the Transmission Provider and Transmission Owner with proof that it meets the requirements of Article 11.5 and 18.3. Any attempted assignment that violates this Article is void and ineffective. Any assignment under this LGIA shall not relieve a Party of its obligations, nor shall a Party’s

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obligations be enlarged, in whole or in part, by reason thereof. Where required, consent to assignment will not be unreasonably withheld, conditioned or delayed.

ARTICLE 20. SEVERABILITY

20.1 Severability. If any provision in this LGIA is finally determined to be invalid, void or unenforceable by any court or other Governmental Authority having jurisdiction, such determination shall not invalidate, void or make unenforceable any other provision, agreement or covenant of this LGIA; provided that if the Interconnection Customer (or any non-party, but only if such non-party is not acting at the direction of either the Transmission Provider or Transmission Owner) seeks and obtains such a final determination with respect to any provision of the Alternate Option (Article 5.1.2), or the Negotiated Option (Article 5.1.4), then none of these provisions shall thereafter have any force or effect and the Parties’ rights and obligations shall be governed solely by the Standard Option (Article 5.1.1).

ARTICLE 21. COMPARABILITY

21.1 Comparability. The Parties will comply with all applicable comparability and code of conduct laws, rules and regulations including such laws, rules and regulations of Governmental Authorities establishing standards of conduct, as amended from time to time.

ARTICLE 22. CONFIDENTIALITY

22.1 Confidentiality. Confidential Information shall include, without limitation, all information relating to a Party’s technology, research and development, business affairs, and pricing, and any information supplied by a Party to another Party prior to the execution of this LGIA.

Information is Confidential Information only if it is clearly designated or marked in writing as confidential on the face of the document, or, if the information is conveyed orally or by inspection, if the Party providing the information orally informs the Party receiving the information that the information is confidential. The Parties shall maintain as confidential any information that is provided and identified by a Party as Critical Energy Infrastructure Information (CEII), as that term is defined in 18 C.F.R. Section 388.113(c). Such confidentiality will be maintained in accordance with this Article 22.

If requested by the receiving Party, the disclosing Party shall provide in writing, the basis for asserting that the information referred to in this Article warrants confidential treatment, and the requesting Party may disclose such writing to the appropriate Governmental Authority. Each Party shall be responsible for the costs associated with affording confidential treatment to its information.

22.1.1 Term. During the term of this LGIA, and for a period of three (3) years after the expiration or termination of this LGIA, except as otherwise provided in this Article

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22, each Party shall hold in confidence and shall not disclose to any person Confidential Information.

22.1.2 Scope. Confidential Information shall not include information that the receiving Party can demonstrate: (1) is generally available to the public other than as a result of a disclosure by the receiving Party; (2) was in the lawful possession of the receiving Party on a non‑confidential basis before receiving it from the disclosing Party; (3) was supplied to the receiving Party without restriction by a non-party, who, to the knowledge of the receiving Party after due inquiry, was under no obligation to the disclosing Party to keep such information confidential; (4) was independently developed by the receiving Party without reference to Confidential Information of the disclosing Party; (5) is, or becomes, publicly known, through no wrongful act or omission of the receiving Party or Breach of this LGIA; or (6) is required, in accordance with Article 22.1.7 of this LGIA, Order of Disclosure, to be disclosed by any Governmental Authority or is otherwise required to be disclosed by law or subpoena, or is necessary in any legal proceeding establishing rights and obligations under this LGIA. Information designated as Confidential Information will no longer be deemed confidential if the Party that designated the information as confidential notifies the receiving Party that it no longer is confidential.

22.1.3 Release of Confidential Information. No Party shall release or disclose Confidential Information to any other person, except to its Affiliates (limited by the Standards of Conduct requirements), subcontractors, employees, agents, consultants, or to non-parties who may be or considering providing financing to or equity participation with Interconnection Customer, or to potential purchasers or assignees of Interconnection Customer, on a need‑to‑know basis in connection with this LGIA, unless such person has first been advised of the confidentiality provisions of this Article 22 and has agreed to comply with such provisions. Notwithstanding the foregoing, a Party providing Confidential Information to any person shall remain primarily responsible for any release of Confidential Information in contravention of this Article 22.

22.1.4 Rights. Each Party retains all rights, title, and interest in the Confidential Information that it discloses to the receiving Party. The disclosure by a Party to the receiving Party of Confidential Information shall not be deemed a waiver by the disclosing Party or any other person or entity of the right to protect the Confidential Information from public disclosure.

22.1.5 No Warranties. By providing Confidential Information, no Party makes any warranties or representations as to its accuracy or completeness. In addition, by supplying Confidential Information, no Party obligates itself to provide any particular information or Confidential Information to another Party nor to enter into any further agreements or proceed with any other relationship or joint venture.

22.1.6 Standard of Care. Each Party shall use at least the same standard of care to protect Confidential Information it receives as it uses to protect its own Confidential Information from unauthorized disclosure, publication, or

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dissemination. Each Party may use Confidential Information solely to fulfill its obligations to another Party under this LGIA or its regulatory requirements.

22.1.7 Order of Disclosure. If a court or a Government Authority or entity with the right, power, and apparent authority to do so requests or requires any Party, by subpoena, oral deposition, interrogatories, requests for production of documents, administrative order, or otherwise, to disclose Confidential Information, that Party shall provide the disclosing Party with prompt notice of such request(s) or requirement(s) so that the disclosing Party may seek an appropriate protective order or waive compliance with the terms of this LGIA. Notwithstanding the absence of a protective order or waiver, the Party may disclose such Confidential Information which, in the opinion of its counsel, the Party is legally compelled to disclose. Each Party will use Reasonable Efforts to obtain reliable assurance that confidential treatment will be accorded any Confidential Information so furnished.

22.1.8 Termination of Agreement. Upon termination of this LGIA for any reason, each Party shall, within ten (10) Calendar Days of receipt of a written request from another Party, use Reasonable Efforts to destroy, erase, or delete (with such destruction, erasure, and deletion certified in writing to the requesting Party) or return to the requesting Party, without retaining copies thereof, any and all written or electronic Confidential Information received from the requesting Party, except that each Party may keep one copy for archival purposes, provided that the obligation to treat it as Confidential Information in accordance with this Article 22 shall survive such termination.

22.1.9 Remedies. The Parties agree that monetary damages would be inadequate to compensate a Party for another Party’s Breach of its obligations under this Article 22. Each Party accordingly agrees that the disclosing Party shall be entitled to equitable relief, by way of injunction or otherwise, if the receiving Party Breaches or threatens to Breach its obligations under this Article 22, which equitable relief shall be granted without bond or proof of damages, and the Breaching Party shall not plead in defense that there would be an adequate remedy at law. Such remedy shall not be deemed an exclusive remedy for the Breach of this Article 22, but shall be in addition to all other remedies available at law or in equity. The Parties further acknowledge and agree that the covenants contained herein are necessary for the protection of legitimate business interests and are reasonable in scope. No Party, however, shall be liable for indirect, incidental, or consequential or punitive damages of any nature or kind resulting from or arising in connection with this Article 22.

22.1.10 Disclosure to FERC, Its Staff or a State. Notwithstanding anything in this Article 22 to the contrary, and pursuant to 18 CFR § 1b.20, if FERC or its staff, during the course of an investigation or otherwise, requests information from a Party that is otherwise required to be maintained in confidence pursuant to this LGIA, the Party shall provide the requested information to FERC or its staff, within the time provided for in the request for information. In providing the information to FERC or its staff, the Party must, consistent with 18 CFR § 388.112, request that the information be treated as confidential and non-public

Original Sheet No. 59

by FERC and its staff and that the information be withheld from public disclosure. Parties are prohibited from notifying the other Parties to this LGIA prior to the release of the Confidential Information to FERC or its staff. The Party shall notify the other Parties to this LGIA when it is notified by FERC or its staff that a request to release Confidential Information has been received by FERC, at which time any of the Parties may respond before such information would be made public, pursuant to 18 CFR § 388.112. Requests from a state regulatory body conducting a confidential investigation shall be treated in a similar manner if consistent with the applicable state rules and regulations.

22.1.11 Subject to the exception in Article 22.1.10, any information that a disclosing Party claims is competitively sensitive, commercial or financial information under this LGIA (“Confidential Information”) shall not be disclosed by the receiving Party to any person not employed or retained by the receiving Party, except to the extent disclosure is (i) required by law; (ii) reasonably deemed by the receiving Party to be required to be disclosed in connection with a dispute between or among the Parties, or the defense of litigation or dispute; (iii) otherwise permitted by consent of the disclosing Party, such consent not to be unreasonably withheld; or (iv) necessary to fulfill its obligations under this LGIA or as the Regional Transmission Organization or a Control Area operator including disclosing the Confidential Information to a regional or national reliability organization. The Party asserting confidentiality shall notify the receiving Party in writing of the information that Party claims is confidential. Prior to any disclosures of the that Party’s Confidential Information under this subparagraph, or if any non-party or Governmental Authority makes any request or demand for any of the information described in this subparagraph, the Party who received the Confidential Information from the disclosing Party agrees to promptly notify the disclosing Party in writing and agrees to assert confidentiality and cooperate with the disclosing Party in seeking to protect the Confidential Information from public disclosure by confidentiality agreement, protective order or other reasonable measures.

ARTICLE 23. ENVIRONMENTAL RELEASES

23.1 Each Party shall notify the other Parties, first orally and then in writing, of the release of any Hazardous Substances, any asbestos or lead abatement activities, or any type of remediation activities related to the Generating Facility or the Interconnection Facilities, each of which may reasonably be expected to affect another Party. The notifying Party shall: (i) provide the notice as soon as practicable, provided such Party makes a good faith effort to provide the notice no later than twenty-four hours after such Party becomes aware of the occurrence; and (ii) promptly furnish to the other Parties copies of any publicly available reports filed with any Governmental Authorities addressing such events.

ARTICLE 24. INFORMATION REQUIREMENTS

24.1 Information Acquisition. Transmission Provider, Transmission Owner and the Interconnection Customer shall submit specific information regarding the electrical

Original Sheet No. 60

characteristics of their respective facilities to each other as described below and in accordance with Applicable Reliability Standards.

24.2 Information Submission by Transmission Provider and Transmission Owner The initial information submission by Transmission Provider to Interconnection Customer, with copy provided to Transmission Owner, shall occur no later than one hundred eighty (180) Calendar Days prior to Trial Operation and shall include Transmission or Distribution System information, as applicable and available, necessary to allow the Interconnection Customer to select equipment and meet any system protection and stability requirements, unless otherwise mutually agreed to by the Parties. On a monthly basis, Transmission Owner shall provide Interconnection Customer a status report on the construction and installation of Transmission Owner’s Interconnection Facilities, Transmission Owner’s System Protection Facilities, Distribution Upgrades and Network Upgrades, including, but not limited to, the following information: (1) progress to date; (2) a description of the activities since the last report (3) a description of the action items for the next period; and (4) the delivery status of equipment ordered.

24.3 Updated Information Submission by Interconnection Customer. The updated information submission by the Interconnection Customer to Transmission Provider, with copy to Transmission Owner, including manufacturer information, shall occur no later than one hundred eighty (180) Calendar Days prior to the Trial Operation. Interconnection Customer shall submit to Transmission Provider and Transmission Owner a completed copy of the Generating Facility data requirements contained in Appendix 1 to the LGIP. It shall also include any additional information provided to Transmission Provider for the Interconnection Feasibility Study and Interconnection Facilities Study. Information in this submission shall be the most current Generating Facility design or expected performance data. Information submitted for stability models shall be compatible with Transmission Provider standard models. If there is no compatible model, the Interconnection Customer will work with a consultant mutually agreed to by Transmission Provider and Interconnection Customer to develop and supply a standard model and associated information.

If the Interconnection Customer's data is materially different from what was originally provided to Transmission Provider pursuant to the Interconnection Study Agreement between Transmission Provider and Interconnection Customer, then Transmission Provider will conduct appropriate studies to determine the impact on the Transmission System based on the actual data submitted pursuant to this Article 24.3. The Interconnection Customer shall not begin Trial Operation until such studies are completed.

24.4 Information Supplementation. Prior to the Commercial Operation Date, the Parties shall supplement their information submissions described above in this Article 24 with any and all “as-built” Generating Facility information or “as-tested” performance information that differs from the initial submissions or, alternatively, written confirmation that no such differences exist. The Interconnection Customer shall conduct tests on the Generating Facility as required by Good Utility Practice, such as an open circuit “step voltage” test on the Generating Facility to verify proper operation of the Generating Facility's automatic voltage regulator.

Original Sheet No. 61

Unless otherwise agreed, the test conditions shall include: (1) Generating Facility at synchronous speed; (2) automatic voltage regulator on and in voltage control mode; and (3) a five percent (5 %) change in Generating Facility terminal voltage initiated by a change in the voltage regulators reference voltage. Interconnection Customer shall provide validated test recordings showing the responses in Generating Facility terminal and field voltages. In the event that direct recordings of these voltages is impractical, recordings of other voltages or currents that mirror the response of the Generating Facility’s terminal or field voltage are acceptable if information necessary to translate these alternate quantities to actual Generating Facility terminal or field voltages is provided. Generating Facility testing shall be conducted and results provided to the Transmission Provider and Transmission Owner for each individual generating unit in a station.

Subsequent to the Operation Date, the Interconnection Customer shall provide Transmission Provider and Transmission Owner any information changes due to equipment replacement, repair, or adjustment. Transmission Owner shall provide the Interconnection Customer, with copy to Transmission Provider, any information changes due to equipment replacement, repair or adjustment in the directly connected substation or any adjacent Transmission Owner substation that may affect the Interconnection Customer’s Interconnection Facilities equipment ratings, protection or operating requirements. The Parties shall provide such information no later than thirty (30) Calendar Days after the date of the equipment replacement, repair or adjustment.

ARTICLE 25. INFORMATION ACCESS AND AUDIT RIGHTS

25.1 Information Access. Each Party (the “disclosing Party”) shall make available to the other Parties information that is in the possession of the disclosing Party and is necessary in order for the other Parties to: (i) verify the costs incurred by the disclosing Party for which another Party is responsible under this LGIA; and (ii) carry out its obligations and responsibilities under this LGIA. The Parties shall not use such information for purposes other than those set forth in this Article 25.1 and to enforce their rights under this LGIA.

25.2 Reporting of Non-Force Majeure Events. A Party (the “notifying Party”) shall notify the other Parties when the notifying Party becomes aware of its inability to comply with the provisions of this LGIA for a reason other than a Force Majeure event. The Parties agree to cooperate with each other and provide necessary information regarding such inability to comply, including the date, duration, reason for the inability to comply, and corrective actions taken or planned to be taken with respect to such inability to comply. Notwithstanding the foregoing, notification, cooperation or information provided under this Article shall not entitle any Party receiving such notification to allege a cause for anticipatory breach of this LGIA.

25.3 Audit Rights. Subject to the requirements of confidentiality under Article 22 of this LGIA, each Party shall have the right, during normal business hours, and upon prior reasonable notice to the other Parties, to audit at its own expense the other Parties’ accounts and records pertaining to the Parties’ performance or the Parties’ satisfaction of obligations under this LGIA. Such audit rights shall include audits of the other Parties’ costs, calculation of invoiced amounts, the Transmission Provider’s efforts to allocate

Original Sheet No. 62

responsibility for the provision of reactive support to the Transmission or Distribution System, as applicable, the Transmission Provider’s efforts to allocate responsibility for interruption or reduction of generation, and each Party’s actions in an Emergency Condition. Any audit authorized by this Article shall be performed at the offices where such accounts and records are maintained and shall be limited to those portions of such accounts and records that relate to each Party’s performance and satisfaction of obligations under this LGIA. Each Party shall keep such accounts and records for a period equivalent to the audit rights periods described in Article 25.4.

25.4 Audit Rights Periods.

25.4.1 Audit Rights Period for Construction-Related Accounts and Records. Accounts and records related to the design, engineering, procurement, and construction of Transmission Owner’s Interconnection Facilities, Transmission Owner’s System Protection Facilities, Distribution Upgrades and Network Upgrades shall be subject to audit for a period of twenty-four months following Transmission Owner’s issuance of a final invoice in accordance with Article 12.2.

25.4.2 Audit Rights Period for All Other Accounts and Records. Accounts and records related to a Party’s performance or satisfaction of all obligations under this LGIA other than those described in Article 25.4.1 shall be subject to audit as follows: (i) for an audit relating to cost obligations, the applicable audit rights period shall be twenty-four months after the auditing Party’s receipt of an invoice giving rise to such cost obligations; and (ii) for an audit relating to all other obligations, the applicable audit rights period shall be twenty-four months after the event for which the audit is sought.

25.5 Audit Results. If an audit by a Party determines that an overpayment or an underpayment has occurred, a notice of such overpayment or underpayment shall be given to the Party or from whom the overpayment or underpayment is owed together with those records from the audit which support such determination.

ARTICLE 26. SUBCONTRACTORS

26.1 General. Nothing in this LGIA shall prevent a Party from utilizing the services of any subcontractor as it deems appropriate to perform its obligations under this LGIA; provided, however, that each Party shall require its subcontractors to comply with all applicable terms and conditions of this LGIA in providing such services and each Party shall remain primarily liable to the other Party for the performance of such subcontractor.

26.2 Responsibility of Principal. The creation of any subcontract relationship shall not relieve the hiring Party of any of its obligations under this LGIA. The hiring Party shall be fully responsible to the other Party for the acts or omissions of any subcontractor the hiring Party hires as if no subcontract had been made; provided, however, that in no event shall the Transmission Provider or Transmission Owner be liable for the actions or inactions of the Interconnection Customer or its subcontractors with respect to obligations of the Interconnection Customer under Article 5 of this LGIA. Any applicable obligation imposed by this LGIA upon the hiring Party shall be equally binding upon, and shall be construed as having application to, any subcontractor of such Party.

Original Sheet No. 63

26.3 No Limitation by Insurance. The obligations under this Article 26 will not be limited in any way by any limitation of subcontractor’s insurance.

ARTICLE 27. DISPUTES

27.1 Submission. In the event any Party has a dispute, or asserts a claim, that arises out of or in connection with this LGIA or its performance, such Party (the “disputing Party”) shall provide the other Parties with written notice of the dispute or claim (“Notice of Dispute”). Such dispute or claim shall be referred to a designated senior representative of each Party for resolution on an informal basis as promptly as practicable after receipt of the Notice of Dispute by the non-disputing Parties. In the event the designated representatives are unable to resolve the claim or dispute through unassisted or assisted negotiations within thirty (30) Calendar Days of the non-disputing Parties’ receipt of the Notice of Dispute, such claim or dispute shall be submitted for resolution in accordance with the dispute resolution procedures of the Tariff.

ARTICLE 28. REPRESENTATIONS, WARRANTIES, AND COVENANTS

28.1 General. Each Party makes the following representations, warranties and covenants:

28.1.1 Good Standing. Such Party is duly organized, validly existing and in good standing under the laws of the state in which it is organized, formed, or incorporated, as applicable; that it is qualified to do business in the state or states in which the Generating Facility, Interconnection Facilities and Network Upgrades owned by such Party, as applicable, are located; and that it has the corporate power and authority to own its properties, to carry on its business as now being conducted and to enter into this LGIA and carry out the transactions contemplated hereby and perform and carry out all covenants and obligations on its part to be performed under and pursuant to this LGIA.

28.1.2 Authority. Such Party has the right, power and authority to enter into this LGIA, to become a Party hereto and to perform its obligations hereunder. This LGIA is a legal, valid and binding obligation of such Party, enforceable against such Party in accordance with its terms, except as the enforceability thereof may be limited by applicable bankruptcy, insolvency, reorganization or other similar laws affecting creditors’ rights generally and by general equitable principles (regardless of whether enforceability is sought in a proceeding in equity or at law).

28.1.3 No Conflict. The execution, delivery and performance of this LGIA does not violate or conflict with the organizational or formation documents, or bylaws or operating agreement, of such Party, or any judgment, license, permit, order, material agreement or instrument applicable to or binding upon such Party or any of its assets.

28.1.4 Consent and Approval. Such Party has sought or obtained, or, in accordance with this LGIA will seek or obtain, each consent, approval, authorization, order, or acceptance by any Governmental Authority in connection with the execution,

Original Sheet No. 64

delivery and performance of this LGIA, and it will provide to any Governmental Authority notice of any actions under this LGIA that are required by Applicable Laws and Regulations.

ARTICLE 29. {RESERVED}

ARTICLE 30. MISCELLANEOUS

30.1 Binding Effect. This LGIA and the rights and obligations hereof, shall be binding upon and shall inure to the benefit of the successors and assigns of the Parties hereto.

30.2 Conflicts. In the event of a conflict between the body of this LGIA and any attachment, appendices or exhibits hereto, the terms and provisions of the body of this LGIA shall prevail and be deemed the final intent of the Parties.

30.3 Rules of Interpretation. This LGIA, unless a clear contrary intention appears, shall be construed and interpreted as follows: (1) the singular number includes the plural number and vice versa; (2) reference to any person includes such person’s successors and assigns but, in the case of a Party, only if such successors and assigns are permitted by this LGIA, and reference to a person in a particular capacity excludes such person in any other capacity or individually; (3) reference to any agreement (including this LGIA), document, instrument or tariff means such agreement, document, instrument, or tariff as amended or modified and in effect from time to time in accordance with the terms thereof and, if applicable, the terms hereof; (4) reference to any Applicable Laws and Regulations means such Applicable Laws and Regulations as amended, modified, codified, or reenacted, in whole or in part, and in effect from time to time, including, if applicable, rules and regulations promulgated thereunder; (5) unless expressly stated otherwise, reference to any Article, Section or Appendix means such Article of this LGIA or such Appendix to this LGIA, or such Section to the LGIP or such Appendix to the LGIP, as the case may be; (6) “hereunder”, “hereof”, “herein”, “hereto” and words of similar import shall be deemed references to this LGIA as a whole and not to any particular Article or other provision hereof or thereof; (7) “including” (and with correlative meaning “include”) means including without limiting the generality of any description preceding such term; and (8) relative to the determination of any period of time, “from” means “from and including”, “to” means “to but excluding” and “through” means “through and including”.

30.4 Entire Agreement. This LGIA, including all Appendices and Schedules attached hereto, constitutes the entire agreement between the Parties with reference to the subject matter hereof, and supersedes all prior and contemporaneous understandings or agreements, oral or written, between the Parties with respect to the subject matter of this LGIA. There are no other agreements, representations, warranties, or covenants, which constitute any part of the consideration for, or any condition to, any Party’s compliance with its obligations under this LGIA.

30.5 No Third Party Beneficiaries. This LGIA is not intended to and does not create rights, remedies, or benefits of any character whatsoever in favor of any persons, corporations, associations, or entities other than the Parties, and the obligations herein assumed are

Original Sheet No. 65

solely for the use and benefit of the Parties, their successors in interest and, where permitted, their assigns.

30.6 Waiver. The failure of a Party to this LGIA to insist, on any occasion, upon strict performance of any provision of this LGIA will not be considered a waiver of any obligation, right, or duty of, or imposed upon, such Party.

Any waiver at any time by any Party of its rights with respect to this LGIA shall not be deemed a continuing waiver or a waiver with respect to any other failure to comply with any other obligation, right, duty of this LGIA. Termination or Default of this LGIA for any reason by the Interconnection Customer shall not constitute a waiver of the Interconnection Customer's legal rights to obtain Interconnection Service from the Transmission Provider. Any waiver of this LGIA shall, if requested, be provided in writing.

30.7 Headings. The descriptive headings of the various Articles of this LGIA have been inserted for convenience of reference only and are of no significance in the interpretation or construction of this LGIA.

30.8 Multiple Counterparts. This LGIA may be executed in two or more counterparts, each of which is deemed an original but all constitute one and the same instrument.

30.9 Amendment. The Parties may by mutual agreement amend this LGIA by a written instrument duly executed by all of the Parties.

30.10 Modification by the Parties. The Parties may by mutual agreement amend the Appendices to this LGIA by a written instrument duly executed by all of the Parties. Such amendment shall become effective and a part of this LGIA upon satisfaction of all Applicable Laws and Regulations.

30.11 Reservation of Rights. Transmission Provider shall have the right to make a unilateral filing with FERC to modify this LGIA with respect to any rates, terms and conditions, charges, classifications of service, rule or regulation under Section 205 or any other applicable provision of the Federal Power Act and FERC’s rules and regulations thereunder, and Transmission Owner and Interconnection Customer shall have the right to make a unilateral filing with FERC to modify this LGIA pursuant to Section 206 or any other applicable provision of the Federal Power Act and FERC’s rules and regulations thereunder; provided that each Party shall have the right to protest any such filing and to participate fully in any proceeding before FERC in which such modifications may be considered. Nothing in this LGIA shall limit the rights of the Parties or of FERC under Sections 205 or 206 of the Federal Power Act and FERC’s rules and regulations thereunder, except to the extent that the Parties otherwise mutually agree as provided herein.

30.12 No Partnership. This LGIA shall not be interpreted or construed to create an association, joint venture, agency relationship, or partnership among or between the Parties or to impose any partnership obligation or partnership liability upon any Party. No Party shall have any right, power or authority to enter into any agreement or undertaking for, or act on behalf of, or to act as or be an agent or representative of, or to otherwise bind, the other Parties.

Original Sheet No. 66

IN WITNESS WHEREOF, the Parties have executed this Agreement in multiple originals; each of which shall constitute and be an original Agreement among the Parties.

Midcontinent Independent System Operator, Inc.

By: /s/William C. Phillips_______________________

Name:William C. Phillips_______________________

Title:Vice President, Reliability & Security Relations

Interstate Power and Light Company

By:/s/Tom L. Aller____________

Name:Tom L. Aller ________

Title:President_______________

ITC MIDWEST LLC, a Michigan limited liability company

By:  ITC Holdings Corp., a Michigan corporation, its sole member

By: /s/Douglas C. Collins__________

Name:  Douglas C. Collins__________

Title:  Vice President______________

Appendices to LGIA

Original Sheet No. 67

Appendix A	Generating Facilities and Interconnection Facilities
Appendix B	{Reserved}
Appendix C	Interconnection Details
Appendix D	Security Arrangements Details
Appendix E	Commercial Operation Date
Appendix F	Addresses for Delivery of Notices and Billings

Appendix A

To LGIA

Generating Facilities and Interconnection Facilities

This LGIA documents the generating stations interconnected to the Transmission Owner’s Transmission System as of the Effective Date of the Asset Sale Agreement between ITC Midwest LLC and Interstate Power and Light. Attachment A.1 - Interconnection Facilities lists the names of the generating stations, their location and their size.

The interconnections to the electric transmission grid are detailed in Appendix C - Interconnection Details.

2009 Amendment - This LGIA is being amended and restated to account for the upgrades to the Interconnection Facilities at the Transmission Owner’s Lansing substation. The need for these upgrades is being driven by the Interconnection Customer’s project of installing a selective catalytic reduction system, associated ID fans and a bag house for unit #4 at its Lansing Generating Station. These upgrades are captured in sections A1 in Appendix A, section B1 in Appendix B, and section C1 in Appendix C below.

A1: Lansing Generating Station

A1-1:Description of Generating Facility:

The Interconnection Customer has a 335 MW net NRIS and 4 MW net ERIS Generating Facility connected to the Transmission Owner’s Lansing Substation. A description of the Generating Facility can be seen in Attachment A.1 below.

Original Sheet No. 68

A1-2:Interconnection Facilities:

A1-2(a) Points of Interconnection.

The Point of Interconnection for the existing Lansing Generating Unit #2, #1 and #2 station service transformer, Lansing Unit #3 reserve station service transformer, Lansing Unit #4 reserve station service transformer, and the new auxiliary transformer T-4C is on the 69 kV bus at the Transmission Owner’s Lansing substation. The Point of Interconnection for the existing Lansing Generating Unit #3, Lansing Generating Unit #4, and the new auxiliary transformer T-4D is on the 161 kV bus at the Transmission Owner’s Lansing substation.

The Point of Change of Ownership for existing Lansing Generating Unit #2 occurs before the isolation switches on 69 kV circuit breaker G2. The Point of Change of Ownership for #1 and #2 station service transformer occurs before the isolation switches on 69 kV circuit breaker G1. The Point of Change of Ownership for the existing Lansing Unit #3 reserve station service transformer occurs before the isolation switches on 69 kV circuit breaker 465. The Point of Change of Ownership for the existing Lansing Unit #4 reserve station service transformer occurs before the isolation switches on 69 kV circuit breaker 462. The Point of Change of Ownership for the existing Lansing Generating Unit #3 occurs before the isolation switches on 161 kV circuit breaker G3. The Point of Change of Ownership for the existing Lansing Generating Unit #4 occurs before the isolation switches on 161 kV circuit breaker G4.

The Point of Change of Ownership for the new auxiliary transformer T-4D will occur before the isolation switches on 161 kV circuit breakers # 475. The Point of Change of Ownership for the new auxiliary transformer T-4C will occur before the isolation switches on the new 69 kV circuit breaker that will be installed on the Transmission Owner’s 69 kV bus. A system map showing demarcation points and an overview of the connection to the Transmission System and a one-line of the Transmission Owner’s Lansing substation can be found in Appendix C, Sections C1-2a and C1-2b, respectively.

A1-2(b) Interconnection Facilities (including metering equipment) to be constructed by Interconnection Customer.

The Interconnection Customer’s Interconnection Facilities shall include equipment connecting the Generating Facility to the Point of Change of Ownership. These Interconnection Facilities shall be installed, owned, operated, and maintained by the Interconnection Customer.

The new Interconnection Customer’s Interconnection Facilities to accommodate this project shall include:

Original Sheet No. 69

(1) One (1) new 69 kV circuit breaker bay complete with circuit breaker, isolating disconnect switches, dead-end, bus, steel, insulators, and foundations. Protective and control equipment will also be install for the reliable operation of one (1) 69,000/13,800 volt no-load tap changing transformer which will be installed in the Transmission Owner’s Lansing Substation.

(2) One (1) new 161,000/13,800 volt no-load tap changing transformer will be installed in the Transmission Owner’s Lansing Substation.

(3) Interconnection Customer will provide RTU/SCADA Generating Facility and Interconnection Customer Interconnection Facilities data including bit not limited to MW, MVAR, MWhr, MVARhr, volts, amps, breaker status, and station battery alarm to Transmission Owner’s Operations Center and Transmission Provider, and to the Local Balancing Authority.

(4) The Interconnection Customer will provide revenue metering per Transmission Owner and Local Balancing Authority specification.

Interconnection Facilities to be constructed by the Interconnection Customer can be seen on the one-line diagram in Appendix C, Section C1-1.

A1-2(c) Interconnection Facilities to be Purchased by the Interconnection Customer from the Transmission Owner

The Interconnection Facilities to be purchased by the Interconnection Customer from the Transmission Owner are as follows:

(1) One (1) 161 kV circuit breaker #475.

(2) Two (2) 161 kV isolation switches.

(3) Two (2) 161 kV switch stands.

The total cost of the assets to be sold is $109,579. A detailed cost estimate can be scene in Appendix C, Section C1-3a.

A1-2(d) Interconnection Facilities to be Constructed by the Transmission Owner

The Interconnection Facilities to be constructed by the Transmission Owner are as follows:

(1) The Transmission Owner will expand the existing fence and ground grid in the Transmission Owner’s Lansing substation to provide enough space for the Interconnection Facilities to be constructed by the Interconnection Customer.

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(2) The existing relaying and controls for 161 kV circuit breaker #475 will be removed.

The Interconnection Facilities to be constructed by the Transmission Owner at the Lansing substation will be funded by the Interconnection Customer and are expected to cost $95,640 (Estimate at ± 20% accuracy in 2009 dollars).A detailed cost estimate is provided in Appendix C, Section C1-3b.

The Interconnection Customer will be responsible to pay the actual costs incurred in designing and constructing of the Interconnection Facilities described in Appendix A, Section A1-2(d).

A1-3:Network Upgrades

None

2013 Amendment - This GIA is being amended and restated to account for the upgrades to Interconnection Facilities and network facilities at Ottumwa Generating Station (“OGS”). The need for upgrades at the Generating Facility is driven by the installation of an air quality control system (“AQCS”) at OGS. The AQCS installation will include the addition of new main and reserve auxiliary transformer units and the addition of a new high side reserve auxiliary breaker. In conjunction with those changes, the 161 kV line currently connecting the reserve auxiliary transformers to the 161 kV bus at Transmission Owner’s OGS substation will be removed from the 161 kV bus and re-terminated at a breaker and ½ position at the Transmission Owner’s OGS substation.

In December 2007, the Transmission Owner purchased the transmission assets of Interstate Power and Light (“IP&L”). Prior to the transmission asset sale from IP&L to the Transmission Owner, IP&L shared ownership of both the OGS Generating Facility and the OGS transmission substation facilities with MidAmerican Energy Company (“MEC”), where MEC owned 52% of the generating facility and transmission facilities, and IP&L owned the remaining 48% of those facilities. A May 22, 1981 Facilities and Operating Agreement among the predecessors of IP&L and predecessors of MEC provides that IP&L acts as agent for the construction, operation, and maintenance of the OGS Generating Facility and transmission facilities, and subsequent to the December 7, 2007 asset sale, the Transmission Owner assumed the role of agent for the OGS transmission facilities. The OGS Generating Facility upgrades and OGS transmission facilities upgrades represented under this 2013 amendment of the Agreement will be jointly owned by MEC and the Transmission Owner, with the Interconnection Customer acting as agent for the OGS Generating Facility upgrades and Transmission Owner acting as agent for the transmission facilities upgrades.

The Interconnection Customer will be responsible for the costs associated with the Interconnection Facilities, and the Transmission Owner will be responsible for the cost of the Network Upgrade.

A2: Ottumwa Generating Station

A2-1: Description of Generating Facility

Original Sheet No. 71

The Interconnection Customer has a 765 MW Net NRIS Generating Facility composed of a single generating unit connected to the Transmission Owner’s OGS Substation.

An Interconnection Customer one line and an overview of the plant are provided in Exhibit C4-1.

A2-2: Interconnection Facilities

A2-2(a) Points of Interconnection and Change of Ownership

The Point of Interconnection for the Ottumwa Generating Station is at the Transmission Owner’s 161 kV bus. The Points of Change of Ownership for generating unit #1 are at the Transmission Owner’s side of the bus connecting switch # 279 to bus L4 and Transmission Owner’s side of the bus connecting switch #179 to bus L1. The Point of Change of Ownership for the 161 kV line connecting the Interconnection Customer’s reserve auxiliary transformers to the new breaker and ½ terminal will be at the dead-end bells connecting the 161 kV line to the Interconnection Customer’s dead end at the Generating Facility. A system map is provided as Exhibit C4-2b, and a transmission facilities one-line is provided as Exhibit C4-2a.

A2-2(b) Interconnection Facilities to be Constructed by Transmission Owner.

Transmission Owner will relocate the existing 161 kV line connecting the Generating Facilities reserve auxiliary transformers to bus L2 from bus L2 to a new 161 kV breaker and ½ terminal between circuit breakers numbered 6140 and 6130. Those Interconnection Facilities will be dedicated to the Generating Facility and owned by the Transmission Owner. Interconnection Customer will be responsible for the cost of those Interconnection Facilities. A listing of the major equipment for the Interconnection Facilities upgrade is provided below, and an estimate of the cost of those facilities is provided as Exhibit C4-3a.

• 2- (two) Steel Dead End Structures

• 3-(three) Equipment Stands

• 3-(three)Capacitive Voltage Transformers

• 1-(one) Relay Panel

• 3-(three) Surge Arresters

• 1000’ 161 kV bus

• 1125’ Control Cable

• 30’ Conduit

The estimated cost of OGS Interconnection Facilities is $572,290. The Interconnection Customer will be responsible for the cost of the Interconnection Facilities upgrade.

A2-2(c) Network Upgrades to be Constructed by Transmission Owner

Transmission Owner will remove the 161 kV line connecting the reserve auxiliary transformers terminate the line to reserve auxiliary transformers at a new breaker and ½ terminal on the existing 161 kV bus. A new circuit breaker, disconnect switches and bus work will be added to the existing bus to accommodate

Original Sheet No. 72

connection of the line to the reserve auxiliary transformers. A listing of major equipment is provided below, and an estimate of the cost of those facilities is provided as Exhibit C4-3b. A preliminary general arrangement drawing of the upgrade is provided as Exhibit C4-2b. The Transmission Owner will fund the cost of the Network Upgrades.

• 2-(two) Steel Equipment Stands

• 2-(two) Disconnect Switches, 161 kV, 3 phase, gang-operated, 2,000A, 100kA momentary, 750 kV BIL

• 1-(one) Circuit Breaker, 161 kV, 2,000A, 40KA interrupting rating

• 1,000’ - 161 kV bus, minimum 2,000A rating

• 1,750’ - Control cable

• 30’ - Conduit

The estimated cost of OGS Network Upgrades is $498,452. The Transmission Owner will be responsible for the cost of the OGS Network Upgrade.

Attachment A.1

Original Sheet No. 73

STEAM GENERATING UNITS
Steam Generating Units	Location	Unit Rating (MVA)	Unit Reactive Capacity (MVAR) (Max)	Unit Reactive Capacity (MVAR) (Min)	Unit Net MW	NRIS	ERIS	Switch Diagram No.
Burlington Generating Station (BGS)	Burlington, IA	236	75	-50	222.0	222.0		T 37
Dubuque 3 (DBQ 3)	Dubuque, IA	36	9	-9	30.0	30.0		T 62
Dubuque 4 (DBQ 4)	Dubuque, IA	44	10	-10	37.0	37.0		T 62
Emery 13	Mason City, IA	301	160	-90	256.0	256.0		T 70
Fox Lake 1	Sherburn, MN	14	3	-3	12.0	12.0		T 08
Fox Lake 3	Sherburn, MN	96	30	-25	96.0	96.0		T 08
Kapp 2	Clinton, IA	257	100	-33	236.0	236.0		T 66
Lansing 4	Lansing, IA	305	100	-50	280.0	280.0		T 58
Ottumwa Generating Station (OGS)*	Chillicothe, IA	807	200	-150	765	765		T 16
Prairie Creek 1	Cedar Rapids, IA	16	7	-4	14.6	14.6		T 38
Prairie Creek 3	Cedar Rapids, IA	54	19	-16	50.5	50.5		T 38
Prairie Creek 4	Cedar Rapids, IA	175	95	-73	159.0	149.0		T 38
Sutherland 1	Marshalltown, IA	44	16	-22	35.0	35.0		T 18
Sutherland 3	Marshalltown, IA	96	37	-27	82.0	82.0		T 18

Original Sheet No. 74

* - OGS is a Joint Owned Unit. IPL is the operator of OGS and represents the entire OGS plant in this Agreement. IPL owns 48% of OGS, and MidAmerican Energy Company owns 52%. Each company’s NRIS rights are allocated based on their respective ownership shares of the unit.Attachment A.1

COMBUSTION TURBINE UNITS
Combustion Turbine Units	Location	Unit Rating (MVA)	Unit Reactive Capacity (MVAR) (Max)	Unit Reactive Capacity (MVAR) (Min)	Unit Net MW	NRIS	ERIS	Switch Diagram No.
BGS 1, 2	Burlington, IA	21	7	-4	36.0	36.0		T 37
BGS 3, 4	Burlington, IA	21	7	-4	36.0	36.0		T 37
Centerville 1, 2	Centerville, IA	32	11	-5	60.0	51.1	8.9	T 15
Emery 11	Mason City, IA	204	110	-65	173.4	173.4		T 70
Emery 12	Mason City, IA	201	110	-65	173.4	173.4		T 70
Grinnell 1	Grinnell, IA	28	11	-5	30.0	30.0		T 17
Grinnell 2	Grinnell, IA	28	11	-5	25.0	25.0		T 17
Lime Creek 1	Mason City, IA	49	10	-5	44.0	44.0		T 55
Lime Creek 2	Mason City, IA	49	10	-5	48.0	48.0		T 55
Red Cedar 1	Cedar Rapids, IA	26	-----	-----	24.0			Dist.
Sutherland 1	Marshalltown, IA	70	16	-22	65.0	65.0		T 18
Sutherland 2	Marshalltown, IA	70	16	-22	65.0	65.0		T 18
Sutherland 3	Marshalltown, IA	70	16	-22	69.0	69.0		T 18

Original Sheet No. 75

Attachment A.1

DIESEL UNITS
Diesel Units	Location	Unit Rating (MVA)	Unit Reactive Capacity (MVAR) (Max)	Unit Reactive Capacity (MVAR) (Min)	Unit Net MW	NRIS	ERIS	Switch Diagram No.
Centerville - 3 units	Centerville, IA	2.5	----	----	6.4		6.4	T 15
Dubuque - 2 units	Dubuque, IA	2.5	----	----	4.5		4.5	T 62
Hills - 2 units	Hills, MN	2.5	----	----	4.0		4.0	Dist.
Lansing - 2 units	Lansing, IA	1.25	----	----	2.0		2.0	T 58

Appendix B

To LGIA

2009 Amendment - Lansing

B1: Lansing Generation Station

B1-1:Milestones

B1-1(a) Interconnection Customer Milestones

No.	Description	Date
1.	Provide the Transmission Owner with payment in the amount of $205,219 for the Transmission Owner to commence with design and construction of the Transmission Owner Interconnection Facilities and for the facilities to be purchased by the Interconnection Customer from the Transmission Owner.	Within 15 days of the execution of the LGIA by the Parties. - Complete

B1-1(b) Transmission Owner Milestones

Original Sheet No. 76

No.	Description	Date
1.	Begin preliminary engineering and design for the Transmission Owner Interconnection Facilities.	Upon receipt by the Transmission Owner of (1) notice from the Interconnection Customer and (2) receipt by Transmission Owner of $205,219 from the Interconnection Customer. - Complete
2.	Complete construction of the Transmission Owner Interconnection Facilities.	8/21/2009 - Complete
3.	Complete Lansing Substation equipment testing	11/10/2009 - Complete
4.	Complete Control Building equipment testing	11/21/2009 - Complete
5.	Provide Interconnection Customer final cost invoices for the Transmission Owner’s Interconnection Facilities	Within 6 months of completion of construction of the Transmission Owner’s Interconnection Facilities - Complete

2013 Amendment - OGS

B2: Ottumwa Generating Station

B2-1: Milestones

B2-1(a) Interconnection Customer Milestones

No.	Description	Date
1.	Provide the Transmission Owner with payment in the amount of $572,290 for the Transmission Owner to commence with design and construction of the OGS Interconnection Facilities and OGS Network Upgrades for and for the facilities to be purchased by the Interconnection Customer from the Transmission Owner.	Within 15 days of the execution of the amended GIA by the Parties.

B2-1(b) Transmission Owner Milestones

No.	Description	Date
1.	Begin preliminary engineering and design for OGS Interconnection Facilities and OGS Network Upgrades	Upon receipt by the Transmission Owner of $572,290 from the Interconnection Customer.
2.	Complete construction of OGS Network Upgrades	4/1/14
3.	Complete construction and tie-in of Interconnection Facilities	4/19/14
5.	Provide Interconnection Customer final cost invoices for the Interconnection Facilities. Actual cost to Interconnection Customer will be a pro rata share of the total project cost. The Interconnection Customers share of actual cost will be based on the ratio of the estimated cost of Interconnection Facilities to the combined estimated cost of Interconnection Facilities and Network Upgrades.	Within 6 months of completion of construction of Interconnection Facilities and Network Upgrades

Original Sheet No. 77

Appendix C

To LGIA

Interconnection Details

This Appendix C is a part of this LGIA among Interconnection Customer, Transmission Owner and the Transmission Provider and documents the generating stations interconnected to the Transmission Owner’s Transmission System as of the January 18, 2007 Effective Date of the Asset Sale Agreement between ITC Midwest LLC and Interstate Power and Light (IPL).

The unique requirements of each generation interconnection will dictate the establishment of mutually agreeable Interconnection and/or Operating Guidelines that further define the requirements of this LGIA. The Interconnection and/or Operating Guidelines applicable to this LGIA consist of the following information. Additional detail may be provided through attachment to this Appendix C or through electronic means via the web address specified.

1. General Interconnection and Operating Guidelines (if applicable)

1.1 Applicable Standards. In addition to applicable design standards identified in the GIA, Interconnection Customer agrees to comply with the most recent Transmission Owner substation/transmission/protection design guides, standards, and specifications, where applicable, for the design of and procurement for this interconnection. The Transmission Owner design guides, standards, and specifications are available upon request.

In the event that such Transmission Owner design guides, standards or specifications do not address a particular item or issue, Interconnection Customers shall use any other nationally or regionally recognized standard, guide or specification. In the event that there is a conflict between any other standard, guide or specification used by Interconnection Customers and Transmission Owner’s design guides, standards and material/construction specifications, Transmission Owner’s design guides, standards and specifications shall apply.

1.2 Communication Requirements. Interconnection Customer shall provide analog and digital signals including hardened voice communications, as requested by the Transmission Owner and/or the Transmission Provider for RTU/frame relay/or public switched telephone systems, as further defined during detailed engineering and design of the Interconnection Facilities. Interconnection Customer agrees to transmit these signals to Transmission Owner’s control building or to such other location as specified by the Transmission Owner during the detailed design of the Interconnection Facilities and Network Upgrades. Transmission Owner shall provide Interconnection Customer with the necessary substation information at the Transmission Owner’s signals demarcation point. Interconnection Customer will pay all costs associated with receiving such information from Transmission Owner. The specific location of the demarcation point will be established during the detailed design of the Interconnection Facilities.

Original Sheet No. 78

1.3 Metering Requirement. Interconnection Customer shall be responsible for the costs of the installation and ongoing maintenance of the interconnection metering. The primary instrument devices shall be revenue class, wound-type, extended range (if applicable) current transformers and potential transformers that are acceptable to the Transmission Owner. The auxiliary usage metering needs shall be in accordance with local service rules/service application requirements.

1.4 Grounding Requirements. Interconnection Customer shall design, install, and maintain grounding facilities to ground the Interconnection Customer’s Interconnection Facilities, in accordance Applicable Reliability Standards and Good Utility Practice. Interconnection Customer shall be responsible for detailed modeling and evaluation of the interconnected grounding system at the location of the Transmission Owner’s Interconnection Facilities and Interconnection Customer’s Interconnection Facilities. If Transmission Owner so chooses, Transmission Owner shall have the right to approve the grounding system design to insure that the grounding system properly protects the Transmission Owner’s Interconnection Facilities.

1.5 Transmission Line and Substation Connection Configurations. The Parties agree that the connections between Interconnection Customer’s Interconnection Facilities and Transmission Owner’s Interconnection Facilities will be as configured in Appendix C of this LGIA. Exact transmission line locations will be developed by Transmission Owner during the detailed design and regulatory process. Interconnection Customer shall provide the space necessary for the Transmission Owner’s placement of the transmission line facilities.

1.6 Unit Stability Requirements. Interconnection Customer agrees to operate its Generating Facility within the operating requirements of the Transmission System, and the rules of the NERC, Reliability Coordinator and Transmission Provider.

All generator/exciter/governor manufacturers’ data sheets shall be made available to the Transmission Owner or its designated agent for modeling in transient/voltage stability, short circuit, and relay setting calculation programs. This includes generator reactive capability curves and exciter saturation curves.

The Interconnection Customer shall provide power system stabilizer data, if applicable, the Generator Step-up Transformer (GSU) data, and the generation plant/station auxiliary load data.

1.7 Equipment Ratings. Transmission Owner will determine the individual equipment ratings for specific Transmission Owner’s Interconnection Facilities and Network Upgrades during the detailed design of the facilities. Interconnection Customer shall size the Interconnection Customer’s Interconnection Facilities using Applicable Reliability Standards, Good Utility Practice and the information provided in the Interconnection Evaluation Study in order that the Interconnection Customer’s Interconnection Facilities appropriately coordinate with the Transmission Owner’s Interconnection Facilities.

1.8 Short Circuit Requirements. Transmission Owner will determine the required short circuit ratings for all Transmission Owner’s Interconnection Facilities and Network Upgrades during the detailed design of such items. Interconnection Customer agrees to provide appropriately sized or short circuit-rated Interconnection Customer’s Interconnection Facilities comparable to those required by Transmission Owner using Applicable Reliability Standards, Good Utility Practice and the information provided in the Interconnection Evaluation Study.

Original Sheet No. 79

Interconnection Customer shall provide the GSU impedance data and the lines to the Point of Interconnection including the positive, negative and zero sequence values, to be used in calculating the fault impedance.

1.9 Synchronizing Requirements. In addition to requirements defined in Section 2 of this Appendix C, Transmission Owner will furnish Transmission System bus potentials that may be used by Interconnection Customer for synchronizing the combined Generating Facility to Transmission Owner’s Transmission System. These potentials will be provided to the Interconnection Customer at the Transmission Owner’s signal demarcation point, as necessary.

Setting changes of any synchronizing devices shall be approved by the Transmission Owner or its designated agent, with a hard copy of the changes forwarded to the Transmission Owner.

1.10 Generation Control Requirements. N/A - This Interconnection Agreement is for a fleet of existing generating stations.

1.11 Power Factor Design Criteria. Interconnection Customer agrees to operate its Generating Facility, as directed, to produce or absorb reactive power at the Point of Interconnection within the design limitations of the Generating Facility.

1.12 Energization, Inspection and Testing Requirements. The Transmission Owner and Generating Facility interconnection facilities were initially inspected and tested to support various operations dates for each of the generating facilities. There is no requirement for this inspection or testing.

1.13 If applicable, the unique requirements, if any, of the Transmission Owner to which the Generating Facility will be physically interconnected. Any changes to the Generating Facility net VAR capabilities, including changes to either net static or net dynamic capability, shall be approved by the Transmission Owner or its designated agent, such approval shall not be unreasonably withheld.

1.14 Maintenance and Testing. The Transmission Owner and Generation Facility Owner interconnection facilities shall be tested and maintained with a combination of condition based and frequency based programs following Good Utility Practices. The facilities shall be tested on a five year cycle and maintained in accordance with the NERC Reliability Standards and Regional Entity Program.

1.15 Switching and Tagging. The Interconnection Customer shall comply with the Transmission Owner’s or its designated agent’s most recent version of the Switching and Tagging procedures for switching under the direction of the Transmission Owner. For switching on Interconnection Customer owned equipment the Interconnection Customer switching procedures shall be used. Electric Transmission and Distribution Switching and Hold Card Procedures are available upon request.

1.16 Low Voltage Ride-Through Capability (LVRT). The generating stations associated with this LGIA were operating prior to the FERC order concerning LVRT and therefore are not subject to the requirements. Any new generating units will have separate LGIA’s, and LVRT will be addressed in those agreements

1.17 Provision of ancillary services. Interconnection Customer shall provide Ancillary Services to Transmission Owner or its designated agent as required by the Tariff.

1.18 Other. It is expressly understood and agreed that Transmission Owner may, during the term of the LGIA, make changes to its Transmission System. Interconnection Customer agrees to make any modifications, additions or changes to the Interconnection Customer’s Interconnection Facilities that are necessary or required

Original Sheet No. 80

as a result of such change, modification or addition to Transmission Owner’s Transmission System and at Interconnection Customers’ sole cost and expense.

2. Specific System Protection Requirements

General. The Transmission Owner will construct a protective relaying scheme to protect the Transmission System from faults occurring on the Interconnection Customer’s Interconnection Facilities or the Generating Facility, and from faults occurring on the Transmission Owner’s Interconnection Facilities and Transmission System. Interconnection Customer will be responsible for providing protection for the Generating Facility and all associated equipment from faults occurring on its facilities, and from faults occurring on the Transmission Owner’s Transmission System.

Transmission Owner has identified the following specific requirements to ensure prompt removal of any contribution of the Generating Facility to any short circuit occurring on the Transmission System and not otherwise isolated by the Transmission Owner equipment:

2.1 Frequency Protection (IEEE 81). Over-frequency protection for the Generating Facility shall be set at the discretion of Interconnection Customer. Under-frequency protection shall be in accordance with the, applicable Midwest Reliability Organization [MRO or its successor] Standards/Guides as applicable and as amended from time to time.

2.2 Interconnection Customer Breaker Failure Protection (IEEE 50BF). Interconnection Customer agrees to have breaker failure protection as an integral part of the redundant relaying protection in support of its breaker on the high side of the generator step-up transformer. This relay protection shall be coordinated with Transmission Owner in order to trip adjacent substation breakers, in the event the generator breaker fails to successfully open for any reason.

2.3 Synchronism Check Relay (IEEE 25). Interconnection Customer shall synch check the Generating Facility to the Transmission System across the Interconnection Customer-owned breaker installed on the high side of the generator step-up transformers. The Transmission Owner will provide bus voltages to be used for synchronism. Each generating unit of the Generating Facility, if more than one unit, shall include automatic or manual synchronization of the unit to Transmission Owner’s Transmission System.

2.4 Bus Differential Protection (IEEE 87). Interconnection Customer shall provide line current differential relay with fiber to be connected into an identical Transmission Owner current differential relay which will overlap the bus or step-up transformer’s protection. This is to accomplish a bus differential protection scheme to provide coordinated bus differential protection of Transmission Owner’s bus.

2.5 Protection Redundancy. In accordance with Good Utility Practice, Interconnection Customer shall design protection schemes such that no single component failure will prevent the isolation of faults and failed equipment. Interconnection Customer acknowledges that meeting this requirement generally means providing redundant or backup protective schemes, with separate sensing sources, separate trip paths, dual trip coils on breakers, separate control power supplies, etc, provided that Interconnection Customer will provide only one battery system.

3. SPECIFIC TELEMETRY REQUIREMENTS.

Original Sheet No. 81

General: Telemetry is required for the monitoring and status of Interconnection Customer's and Transmission Owner’s equipment. Interconnection Customer shall install and pay the installation cost and monthly communication costs of all required telemetry for the Generating Facility. In general, Transmission Owner requires continuous telemetry of the following:

3.1 Appropriate relaying status of all installed relay equipment.

3.2 Status of all circuit breaker(s) capable of disconnecting the Generating Facility from the Transmission Owner’s Transmission System.

3.3 Instantaneous MW and MVAR of the Generating Facility.

3.4 Instantaneous revenue quality MW and MVAR; and cumulative revenue quality MWhr and MVARhr at all (or possibly corrected to) Points of Interconnection with Transmission Owner and from the Generating Facility.

3.5 Status of auxiliary station service circuit breaker(s).

3.6 Instantaneous 34.5 kV aggregate bus voltage(s).

3.7 Transfer trip communication and generation site transfer trip communication status.

3.8 Changes in energy production of the Generating Facility.

3.9 Other telemetry as required and mutually agreed upon by the Interconnection Customer and Transmission Owner.

4. SPECIFIC OPERATIONAL REQUIREMENTS.

4.1 System Protection Facilities (Relays As They Relate To Operations). Interconnection Customer shall report all generator protective relay events to the Transmission Owner system control center, immediately following Interconnection Customer's discovery of the event. Interconnection Customer shall provide status indication of automatic voltage regulator equipment and any other items that are identified during the detailed design.

4.2 Communication Requirements. Interconnection Customer will provide any communication protocols for proper function between Interconnection Customer's operating systems and Transmission Owner’s operating systems. Interconnection Customer shall pay all fees for such communication facilities and associated monthly services, as necessary, for the Generating Facility.

4.3 Data Reporting Requirements. Interconnection Customer shall supply all information regarding events and status of equipment within the Facility upon request for any event that noticeably affects the operation of the Transmission System. Interconnection Customer shall provide outage schedules, daily/hourly load profiles, and other data upon request of Transmission Owner.

4.4 Emergency Operations, Including System Restoration and Black Start Arrangements. The Interconnection Customer shall provide the Transmission Owner or its designated agent with plant data and plant procedures necessary to coordinate and implement the Transmission Owner or its designated agent black-start plans. In accordance with Good Utility Practice, Interconnection Customer agrees to participate when called upon by Transmission Provider or Transmission Owner, in Transmission Owner’s Black Start Plan for the Generating Facility and Transmission Owner’s Transmission System, as well as any verification testing.

4.5 Identified Must‑Run Conditions.None noted for this Generating Facility.

4.6 Specific Transmission Requirements of Nuclear Units to Abide by All NRC Requirements and Regulations.Not applicable to this interconnection.

Original Sheet No. 82

4.7 Stability Requirements, Including Output.Interconnection Customer agrees to comply with the requirements of the reliability coordinator, Transmission Dispatch Center or (“TDC”), Transmission Provider and/or Transmission Owner in the operation of the Generating Facility.

4.8 Limitations of Operations in Support of Emergency Response. Interconnection Customer agrees to comply with the requirements of the reliability coordinator, Transmission Dispatch Center or (“TDC”), Transmission Provider and/or the Transmission Owner in the operation of the Generating Facility.

5. Transmission Owner shall provide the “as-built” drawings, information and documents regarding the Transmission Owner’s Interconnection Facilities pursuant to Article 5.11 of the GIA.

6. In accordance with Section 9.4 of the GIA, the operating limits established for the Generating Facility under this GIA shall be as provided by Transmission Provider each quarter, as described in Appendix A. Any operating guides necessary following Commercial Operation will be established in accordance with Section 9.3.

7. Use of SPS or Operating Guide. Implementation of an Operating Guide will constitute an interim solution that will permit Interconnection Customer to obtain conditional Interconnection Service until planned for Network Upgrades are constructed. Any Operating Guide will be subject to the approval of the Transmission Owner and Transmission Provider. Minimum requirements for an Operating Guide are as indicated below.

◦ Transmission Owner will control their breaker(s) connected to the Generating Facility and shall be able to trip the Interconnection Customer’s Generating Facility.

◦ Protection schemes must be tested and operative.

◦ Interconnection Customer will operate its Generating Facility as directed by the Transmission Provider and the Transmission Owner.

◦ A termination date consistent with completion of Network Upgrades will be mutually agreed to as part of all Operating Guides accepted by the Transmission Owner and the Transmission Provider.

Transmission Owner does not allow the addition of an SPS to the Transmission Owner’s system. The Transmission Owner will also not allow the addition of an SPS on a system, including the Generating Facility, where the purpose of that SPS is to mitigate a constraint on the Transmission Owner’s system.

8. Voltage and Reactive Power Regulation - Reactive power, voltage regulation and operating requirements will be per Transmission Operator and Transmission Provider directives.  Interconnection Customer will operate the Generating Facilities to a designated within the bandwidth of the voltage schedule target provided by the Transmission Operator in separate communication, at the POI,utilizing the Generating Facility’s power factor design capability as indicated in Section 1.11 of Appendix C. The Interconnection Customer will regulate the Generating Facility’s voltage to the specified set-point within the defined bandwidth stated above using an automatic voltage controller and the inherent reactive power capability in the generator. The Interconnection Customer may also utilize a combination of, if applicable, generator step-up tap connections, load-tap changing transformers, static capacitor banks, shunt reactors and/or dynamic reactive resources to maintain the schedule.

Original Sheet No. 83

The voltage schedule may change from time to time within the limits of the GIA provisions in Section 9.6.2 and within the Generating Facility’s power factor design capability as indicated in Section 1.11 of Appendix C. If a schedule change is needed, appropriate written documentation of the change will be provided to the Interconnection Customer.

The Interconnection Customer is required to have a generator operator available for 24/7 communications with the Transmission Operator. The Transmission Operator may, at any time, request a variance from the schedule in response to system operating/security requirements.

The following exhibits are attached and are included as part of this LGIA.

C1: Lansing Generation Station

C1-1: Interconnection Customer One-Lines

C1-2: Transmission Owner One-Lines and System Map

C1-2a: System Map

C1-2b: Lansing Substation 69 kV One-Line

C1-2c: Lansing Substation 161 kV One-Line

C1-3: Cost Estimates

C1-3a: Facilities to be Purchased by the Interconnection Customer

C1-3b: Facilities to be Constructed by Transmission Owner

C2: Lakefield and Fox Lake Switch Diagram

C3: Appanoose County and Centerville Switch Diagram

C4: Ottumwa Generating Station

C4-1: Interconnection Customer

C4-1a: Interconnection Customer One Line

C4-1b: Interconnection Customer Substation Overview

C4-2: Transmission Owner Facilities Drawing

C4-2a:Transmission Owner One Line

C4-2b:Transmission Owner System Map

C4-2c:Transmission Owner General Arrangement

C4-3:Transmission Owner Cost Estimates

C4-3a: OGS Interconnection Facilities Cost Estimate

C4-3b: OGS Network Upgrade Cost Estimate

C5: Poweshiek County, Grinnell, and Newton Switch Diagram

C6: Marshalltown Switch Diagram

C7: Burlington Generating Station (BGS), Denmark, and Henry Co. Switch Diagram

C8: Prairie Creek Switch Diagram

C9: Lime Creek and Highway 106 Switch Diagram

C10: DBQ Power Sta., Bellevue, and NICC Switch Diagram

C11: Beaver Channel and Rock Creek Switch Diagram

C12: Emery Switch Diagram

Original Sheet No. 84

C1: Lansing Generation Station

C1- Interconnection Customer One-Lines

[Interconnection Customer One-Lines Diagram]

Original Sheet No. 85

C1-2 Transmission Owner One-Lines and System Map

C1-2a: System Map

CEII MATERIAL

Original Sheet No. 86

C1-2b: Lansing Substation 69 kV One-Line

CEII MATERIAL

Original Sheet No. 87

C1-2c: Lansing Substation 161 kV One-Line

CEII MATERIAL

Original Sheet No. 88

C1-3 Cost Estimates

C1-3a: Facilities to be Purchased by the Interconnection Customer

Original Sheet No. 89

C1-3b: Facilities to be Constructed by Transmission Owner

Original Sheet No. 90

C2: Lakefield and Fox Lake Switch Diagram

[Lakefield and Fox Lake Switch Diagram]

Original Sheet No. 91

C3: Appanoose County and Centerville Switch Diagram

[Appanoose County and Centerville Switch Diagram]

Original Sheet No. 92

C4: Ottumwa Generating Station

C4-1: Interconnection Customer Facilities Drawings

C4-1a: Interconnection Customer One Line

[Interconnection Customer One line Diagram]

C4-1b: Interconnection Customer Substation (OGS Plant Sub) Overview

[Interconnection Customer Substation (OGS Plant Sub) Overview Diagram]

Original Sheet No. 93

C4-2: Transmission Owner Facilities Drawing

C4-2a: Transmission Owner One Line

CEII MATERIAL

Original Sheet No. 94

C4-2b Transmission Owner System Map

CEII MATERIAL

Original Sheet No. 95

C4-2c Transmission Owner General Arrangement

CEII MATERIAL

Original Sheet No. 96

C4-3 Transmission Owner Cost Estimates

C4-3a OGS Interconnection Facilities Cost Estimate

Original Sheet No. 97

C4-3b OGS Network Upgrade Cost Estimate

C5: Poweshiek County, Grinnell, and Newton Switch Diagram

[Poweshiek County, Grinnell, and Newton Switch Diagram]

C6: Marshalltown Switch Diagram

[Marshlltown Switch Diagram]

C7: Burlington Generating Station (BGS), Denmark, and Henry Co. Switch Diagram

[Burlington Generating Station (BGS), Denmark, and Henry Co. Switch Diagram]

Original Sheet No. 98

C8: Prairie Creek Switch Diagram

[Prairie Creek Diagram]

C9: Lime Creek and Highway 106 Switch Diagram

[Lime Creek and Highway 106 Switch Diagram]

C10: DBQ Power Sta., Bellevue, and NICC Switch Diagram

[DBQ Power Sta., Bellevue, and NICC Switch Diagram]

C11: Beaver Channel and Rock Creek Switch Diagram

[Beaver Channel and Rock Creek Switch Diagram]

C12: Emery Switch Diagram

[Emery Switch Diagram]

Appendix D

To LGIA

Security Arrangements Details

Infrastructure security of Transmission or Distribution System equipment and operations, as applicable, and control hardware and software is essential to ensure day-to-day Transmission and Distribution System reliability and operational security. The Commission will expect all Transmission Providers, market participants, and Interconnection Customers interconnected to the Transmission or Distribution System, as applicable, to comply with the recommendations provided by Governmental Authorities regarding Critical Energy Infrastructure Information (“CEII”) as that term is defined in 18 C.F.R. Section 388.113(c) and best practice recommendations from the electric reliability authority. All public utilities will be expected to meet basic standards for system infrastructure and operational security, including physical, operational, and cyber-security practices.

Appendix E

To LGIA

Commercial Operation Date

Original Sheet No. 99

[Date]

MISO

Attn: Director, Transmission Services Planning

P.O. Box 4202

Carmel, IN 46082-4202

for overnight deliveries:

720 City Center Drive

Carmel, IN 46032

Re:_____________ Generating Facility

Dear _______________:

On [Date] [Interconnection Customer] has completed Trial Operation of Unit No. ___. This letter confirms that [Interconnection Customer] commenced commercial operation of Unit No. ___ at the Generating Facility, effective as of [Date plus one day].

Thank you.

[Signature]

[Interconnection Customer Representative]

xc:Transmission Owner

Appendix F

To LGIA

Addresses for Delivery of Notices and Billings

Notices:

Transmission Provider:

MISO

Attn: Director, Transmission Services Planning

P.O. Box 4202

Carmel, IN 46082-4202

for overnight deliveries:

720 City Center Drive

Carmel, IN 46032

Original Sheet No. 100

Transmission Owner:

President

ITC Midwest LLC

6750 Chavenelle Drive

Dubuque, Iowa  52002

Phone:  563.585.3540

Fax:       563.585.3654

With a copy to:

General Counsel Utility Operations

ITC Midwest LLC

27175 Energy Way

Novi, MI 48377

Fax: 248.946.3352

Interconnection Customer:

Interstate Power and Light Company

200 First Street SE

PO Box 351

Cedar Rapids, IA, 52406-0351

Attn: President

Facsimile: 319-786-7720

With a copy to:

Alliant Energy Corporate Services, Inc.

4902 Biltmore Lane

Madison, WI, 53718

Attn: General Counsel

Facsimile: 680-458-0143

Billings and Payments:

Transmission Provider:

MISO

Attn: Director, Transmission Services Planning

P.O. Box 4202

Carmel, IN 46082-4202

Original Sheet No. 101

for overnight deliveries:

720 City Center Drive

Carmel, IN 46032

Transmission Owner:

ITC Midwest LLC

P.O. Box 674015

Detroit, MI 48267-4015

Interconnection Customer:

Interstate Power and Light Company

Attention: Accounts Payable Department

1000 Main Street

Dubuque, Iowa 52004-0769

Phone: 563-557-2220

With a copy to:

Interstate Power and Light Company

Attention: Manager, Transmission Planning

200 1st Street S.E.

Cedar Rapids, IA 52401-1409

Alternative Forms of Delivery of Notices (telephone, facsimile or email):

Transmission Provider:

Voice telephone - (317) 249-5759

Facsimile telephone - (317) 249-5703

Email address - elaverty@misoenergy.org

Transmission Owner:

President

ITC Midwest LLC

6750 Chavenelle Drive

Dubuque, Iowa  52002

Phone:  563.585.3650

Fax:  563.585.3654

Email address - DCollins@ITCtransco.com

Interconnection Customer:

Interstate Power and Light Company

200 First Street SE

PO Box 351

Original Sheet No. 102

Cedar Rapids, IA, 52406-0351

Attn: Vice President, Generation

Facsimile: 319-786-7265

EX-12.1

EXHIBIT 12.1

ITC HOLDINGS

Computation of Ratios of Earnings to Fixed Charges

Our ratios of earnings to fixed charges were as follows for the periods indicated in the table below:

	Year Ended December 31,
(In thousands)	2013		2012		2011		2010		2009
Earnings are defined:
Net income	$	233,506	$	187,876	$	171,685	$	145,678	$	130,900
Add: Income tax provision	118,862		108,632		94,749		82,254		77,572
Add: Fixed charges	176,298		162,728		151,586		146,406		134,077
Less: Capitalized interest	7,979		6,694		4,650		3,853		3,868
Earnings as defined	$	520,687	$	452,542	$	413,370	$	370,485	$	338,681
Fixed charges are defined:
Interest expense — net	$	168,319	$	155,734	$	146,936	$	142,553	$	130,209
Add: Capitalized interest	7,979		6,994		4,650		3,853		3,868
Fixed charges as defined	$	176,298	$	162,728	$	151,586	$	146,406	$	134,077
Ratio of earnings to fixed charges	2.95		2.78		2.73		2.53		2.53

____________________________

Our ratios of earnings to fixed charges were computed based on:

• “earnings,” which consist of net income before income taxes and fixed charges, excluding capitalized interest; and

• “fixed charges,” which consist of interest expense including capitalized interest.

EX-21

EXHIBIT 21

EX-23.1

EXHIBIT 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-153016, 333-141430, 333-138048, 333-136657, 333-126942, and 333-126943 on Form S-8 and Registration Statement No. 333-187994 on Form S-3 of our reports dated February 27, 2014, relating to the consolidated financial statements and financial statement schedule of ITC Holdings Corp. and subsidiaries, and the effectiveness of ITC Holdings Corp. and subsidiaries' internal control over financial reporting, appearing in this Annual Report on Form 10-K of ITC Holdings Corp. for the year ended December 31, 2013.

/s/ DELOITTE & TOUCHE LLP

Detroit, Michigan

February 27, 2014

EX-31

EXHIBIT 3.1

AMENDED AND RESTATED ARTICLES OF INCORPORATION

For use by Domestic Profit Corporations

(Please read information and instructions on the last page)

Pursuant to the provisions of Act 284, Public Acts of 1972 the undersigned corporation executes the following Articles:

1.     The present name of the corporation is:  ITC Holdings Corp.

2.     The identification number assigned by the Bureau is:  405-95C.

3.     All former names of the corporation are:  None.

4.     The date of filing of the original Articles of Incorporation was:  November 8, 2002.

The following Amended and Restated Articles of Incorporation supersede the Articles of Incorporation as amended and shall be the Articles of Incorporation for the corporation:

ARTICLE I

Name

The name of the corporation is:  ITC Holdings Corp.

ARTICLE II

Purpose

The purpose or purposes for which the corporation is formed is to engage in any activity within the purposes for which corporations may be formed under the Business Corporation Act of Michigan, as amended (the “MBCA”).

ARTICLE III

Capital Stock

Section 1.  Authorized Shares.  The total authorized shares of the corporation consists of 110,000,000 shares, 100,000,000 of which shall be Common Stock, with no par value (the “Common Stock”) and 10,000,000 of which shall be Preferred Stock, with no par value (the “Preferred Stock”).

Section 2.  Common Stock.  All holders of Common Stock shall have equal rights, preferences and limitations, including equal voting rights, and each holder of Common Stock is entitled to one vote per share, in each case subject to Article VIII.

Section 3.  Preferred Stock.  Shares of Preferred Stock may be issued from time to time in one or more series as may from time to time be determined by the Board of Directors, each of said series to be distinctly designated.  The voting powers, preferences and relative, participating, optional and other special rights, and the qualifications, limitations or restrictions thereof, if any, of each such series may differ from those of any and all other series of Preferred Stock at any time outstanding, and the Board of Directors is hereby expressly granted authority to fix, by resolution, the designation, number, voting powers, preferences and relative, participating, optional and other special rights, and the qualifications, limitations and restrictions thereof, of each such series, including but without limiting the generality of the foregoing, the following:

(a)           The distinctive designation of, and the number of shares of Preferred Stock that shall constitute, such series;

(b)           The rights in respect of dividends, if any, of such series of Preferred Stock, the extent of the preference or relation, if any, of such dividends to the dividends payable on any other class or classes or on any other series of the same or other class or classes of capital stock of the corporation and whether such dividends shall be cumulative or noncumulative;

(c)           The right, if any, of the holders of such series of Preferred Stock to convert the same into, or exchange the same for, shares of any other class or classes or of any other series of the same or any other class or classes of capital stock of the corporation, and the terms and conditions of such conversion or exchange;

(d)           Whether or not shares of such series of Preferred Stock shall be subject to redemption, and the redemption price or prices and the time or times at which, and the terms and conditions on which, shares of such series of Preferred Stock may be redeemed;

(e)           The rights, if any, of the holders of such series of Preferred Stock upon the voluntary or involuntary liquidation, dissolution or winding-up of the corporation or in the event of any merger or consolidation of or sale of assets by the corporation;

(f)            The terms of any sinking fund or redemption or repurchase or purchase account, if any, to be provided for shares of such series of Preferred Stock;

2

(g)           The voting powers, if any, of the holders of any series of Preferred Stock generally or with respect to any particular matter, which may be less than, equal to or greater than one vote per share, and which may, without limiting the generality of the foregoing, include the right, voting as a series by itself or together with the holders of any other series of Preferred Stock or all series of Preferred Stock as a class, to elect one or more directors of the corporation generally or under such specific circumstances and on such conditions, as shall be provided in the resolution or resolutions of the Board of Directors adopted pursuant hereto, including, without limitation, in the event there shall have been a default in the payment of dividends on or redemption of any one or more series of Preferred Stock; and

(h)           Such other powers, preferences and relative, participating, optional and other special rights, and the qualifications, limitations and restrictions thereof, as the Board of Directors shall determine.

ARTICLE IV

Registered Office and Resident Agent

The address and mailing address of the registered office is 30600 Telegraph Road, Bingham Farms, Michigan 48025.  The name of the resident agent is The Corporation Company.

ARTICLE V

Limitation of Director Liability; Indemnification

No director of the corporation shall be personally liable to the corporation or its shareholders for money damages for any action taken, or any failure to take any action, except liability for any of the following:  (1) the amount of a financial benefit received by a director to which he or she is not entitled; (2) intentional infliction of harm on the corporation or its shareholders; (3) a violation of §551 of the MBCA, the Michigan Compiled Laws Annotated 450.1551, Michigan Statutes Annotated 21.200(551); or (4) an intentional violation of criminal law.  If the MBCA hereafter is amended to authorize the further elimination or limitation of the liability of directors, then the liability of a director of the corporation, in addition to the limitation on personal liability contained herein, shall be limited to the fullest extent permitted by the MBCA as so amended.  No amendment or repeal of this Article V shall apply to or have any effect on the liability or alleged liability of any director of the corporation for or with respect to any acts or omissions of such director occurring prior to such amendment or repeal.

To the maximum extent permitted by the MBCA, the corporation shall indemnify any person who was or is a party to or is threatened to be made a party to any threatened, pending, or completed action, suit, or proceeding, whether civil, criminal, administrative, or investigative, formal or informal, including any appeal, by reason of the fact that the person is or was a director or officer of the corporation, or, while serving as a director, officer, employee or agent of the corporation, is or was serving at the request of the corporation as a director, officer, member, partner, trustee, employee, fiduciary, or agent of another foreign or domestic corporation, partnership, limited liability company, joint venture, trust, or other enterprise, including service with respect to employee benefit plans or public service or charitable organizations, against

3

expenses (including actual and reasonable attorney fees and disbursements), liabilities, judgments, penalties, fines, excise taxes, and amounts paid in settlement actually and incurred by him or her in connection with such action, suit, or proceeding.  Indemnification may continue as to a person who has ceased to be a director, officer, employee or agent of the corporation and may inure to the benefit of such person’s heirs, executors and administrators.  The corporation, by provisions in its bylaws or by agreement, may grant to any current or former director, officer, employee or agent of the corporation the right to, or regulate the manner of providing to any current or former director, officer, employee or agent of the corporation, indemnification to the fullest extent permitted by the MBCA.  Any right to indemnification conferred as permitted by this Article V shall not be deemed exclusive of any other right which any person may have or hereafter acquire under any statute (including the MBCA), any other provision of these Articles, any provision of the bylaws, any agreement, any vote of shareholders or the Board of Directors or otherwise.

ARTICLE VI

Compromise, Arrangement, or Plan of Reorganization

When a compromise or arrangement or any plan of reorganization of this corporation is proposed between this corporation and its creditors or any class of them or between this corporation and its shareholders or any class of them, any court of equity jurisdiction within the State of Michigan may, on the application of this corporation or of any creditor or any shareholder thereof, or on the application of any receiver or receivers appointed for this corporation, order a meeting of the creditors or class of creditors, or of the shareholders or class of shareholders, as the case may be, to be affected by the proposed compromise or arrangement or reorganization, to be summoned in such manner as said court directs.

If a majority in number, representing three-fourths (3/4) in value of the creditors or class of creditors, or of the shareholders or class of shareholders, as the case may be, to be affected by the proposed compromise or arrangement or reorganization, agrees to any compromise or arrangement or to any reorganization of this corporation as a consequence of such compromise or arrangement, said compromise or arrangement and said reorganization shall, if sanctioned by the court to which the said application has been made, be binding on all the creditors or class of creditors, and/or on all the shareholders or class of shareholders, as the case may be, and also on this corporation.

ARTICLE VII

Corporate Action Without Meeting of Shareholders

At any time that International Transmission Holdings Limited Partnership (or its affiliates or limited partners (or their respective affiliates)) beneficially owns at least 35 percent of the outstanding Common Stock of the corporation, any action required or permitted by the MBCA to be taken at an annual or special meeting of shareholders may be taken without a meeting, without prior notice and without a vote, if a consent in writing, setting forth the action so taken, is signed by the holders of record of outstanding stock having not less than the minimum number of votes that would be necessary to authorize or take the action at a meeting at which all shares entitled to vote thereon were present and voted.  The written consents shall bear the date of signature of each shareholder who signs the consent.  No written consents shall be effective to take the corporate

4

action referred to unless, within 60 days after the record date for determining shareholders entitled to express consent to or dissent from a proposal without a meeting, written consents dated not more than 10 days before the record date and signed by a sufficient number of shareholders to take the action are delivered to the corporation.  Delivery shall be to the corporation’s registered office, its principal place of business, or an officer or agent of the corporation having custody of the minutes of the proceedings of its shareholders.  Delivery made to a corporation’s registered office shall be by hand or by certified or registered mail, return receipt requested.

Prompt notice of the taking of the corporate action without a meeting by less than unanimous written consent shall be given to shareholders who would have been entitled to notice of the shareholder meeting if the action had been taken at a meeting and who have not consented in writing.  An electronic transmission consenting to an action must comply with Section 407(3) of the MBCA.

For the avoidance of doubt, this Article VII shall cease to apply at any time that International Transmission Holdings Limited Partnership (or its affiliates or limited partners (or their respective affiliates)) fails to beneficially own at least 35 percent of the outstanding Common Stock of the corporation.

ARTICLE VIII

Market Participant Restrictions

The following provisions are included for the purpose of ensuring that the corporation and the corporation’s subsidiary International Transmission Company (“ITC”) each remain independent of Market Participants (as defined below), consistent with the applicable rules, regulations, decisions and orders of the Federal Energy Regulatory Commission (or any successor agency) (the “FERC”) under the Federal Power Act of 1935 (the “Federal Power Act”):

(a)  Definitions.

(1)  “Market Participant” shall have the same meaning as that term has under 18 C.F.R. § 35.34(b)(2) of the FERC’s regulations (or any successor regulation) and other applicable rules, regulations, decisions and orders of the FERC under the Federal Power Act (modified as necessary to apply to an independent transmission company that is a member of a Regional Transmission Organization (as defined in 18 C.F.R. § 35.34(b)(1)), such as ITC), including without limitation: (i) any person or entity that, either directly or through an affiliate (for purposes of this definition, as defined in 18 C.F.R. § 35.34(b)(3)), sells or brokers electric energy, or provides ancillary services to ITC or to the Regional Transmission Organization to which the corporation or its subsidiaries belong, unless the FERC shall have found that such person or entity does not have economic or commercial interests that would be significantly affected by ITC’s or such Regional Transmission Organization’s actions or decisions or (ii) any other person or entity that the FERC shall have found to be a market participant because it has economic or commercial interests that would be significantly affected by the actions or decisions of ITC or of any Regional Transmission Organization to which the corporation or its subsidiaries belong.

(2)  “Beneficially owned” shall have the same meaning as that term has under

5

Regulation 13D-G (or any successor regulation) (“Regulation 13D-G”) promulgated by the Securities and Exchange Commission (or any successor agency) (the “SEC”) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”).

(3)  “Volume Weighted Average Price” means (i) the sum of (x) the number of shares of a class or series of capital stock of the corporation subject to each purchase or sale transaction on the U.S. securities exchange or automated inter-dealer quotation system on which shares of such class or series are primarily traded or quoted on a trading day, (y) multiplied by the price of the shares subject to each such purchase or sale transaction, (ii) divided by the total number of shares of such class or series of capital stock subject to purchase and sale transactions occurring on such exchange or system on such trading day.

(4)  “trading day” means:

(i)  if the class or series of capital stock is listed or admitted for trading on the New York Stock Exchange, a day on which the New York Stock Exchange is open for business;

(ii)  if the class or series of capital stock is not listed on the New York Stock Exchange, a day on which trades may be made on the Nasdaq National Market; or

(iii)  if the class or series of capital stock is not listed on the New York Stock Exchange and not quoted on the Nasdaq National Market, a day on which the principal U.S. securities exchange on which the class or series of capital stock is listed is open for business.

(b)  (1) For purposes of this Article VIII, any determination by the Board of Directors, acting in good faith, (x) that shares of capital stock of the corporation are beneficially owned by a Market Participant, including, in any case, as a member of a “group” (as such term is used in Rule 13d-5 of Regulation 13D-G) or (y) that any person or entity is a member of a group including a Market Participant shall be made solely based on (i) the number of shares of capital stock reported to be beneficially owned by such Market Participant and group members and (ii) the identification of persons or entities as group members of such Market Participant, in each case, as reported as of the date of such determination (A) in filings of such person or entity made with the SEC under Regulation 13D-G, (B) in a declaration provided pursuant to clause (h) of this Article VIII or (C) on the stock transfer books of the corporation.

(2)  A determination by the Board of Directors, acting in good faith, that any person, entity and/or group member is a Market Participant may be based upon a bona fide declaration provided pursuant to clause (h) of this Article VIII.  Except as otherwise provided in clause (h), no person or entity shall be deemed to be a Market Participant unless it has been determined by the Board of Directors to be a Market Participant.

(3)  Any determination made by the Board of Directors under this Article VIII shall be binding upon all shareholders of the corporation.

6

(c)           The corporation shall not issue any shares of capital stock of the corporation or record any transfer of shares of capital stock on the books and records of the corporation if such issuance or transfer would cause any Market Participant, either individually or in the aggregate with its group members, to beneficially own shares constituting five percent or more of the total number of shares of any class or series of capital stock of the corporation outstanding at the time of such issuance or transfer; provided, however, that this clause (c) shall not restrict the corporation from issuing shares of capital stock of the corporation, or recording any transfer of shares of capital stock of the corporation (whether in connection with a primary issuance of shares or a secondary sale by an existing shareholder of the corporation) on the books and records of the corporation, to an investment banking institution, in its capacity as an underwriter or initial purchaser of a public offering or private placement, respectively, of shares of capital stock of the corporation so long as such offering or placement has been approved by the Board of Directors.

(d)           Without limiting the generality of the foregoing and notwithstanding any other provision of these Articles to the contrary, no Market Participant, or any group member of a Market Participant, shall be entitled to vote or give consent in respect of, or direct or control the vote or giving of consent in respect of, shares that such Market Participant, together with its group members, has the right to vote equal to or in excess of five percent of (i) the total number of shares of any class or series of capital stock of the corporation outstanding and entitled to vote or give consent at any time and from time to time, or (ii) the total voting power of all shares of any class or series of capital stock of the corporation outstanding and entitled to vote at any time and from time to time.  Any shares which, pursuant to this clause (d), are not entitled to be voted shall be deemed not to be outstanding when determining the shares entitled to vote on any matter or the presence of a quorum.

(e)           Subject to clause (i) of this Article VIII, without limiting the generality of the foregoing and notwithstanding any other provision of these Articles to the contrary, but subject to applicable law, to the extent any Market Participant, together with its group members, acquires beneficial ownership of shares constituting five percent or more of the total number of shares of any class or series of capital stock of the corporation outstanding at any time, then the corporation (or any of its subsidiaries) shall have the right, exercisable at the sole discretion of the Board of Directors, to redeem (and in the case of any subsidiary of the corporation, the right to repurchase) any shares of capital stock of the corporation beneficially owned by such Market Participant or its group members so that, after giving effect to such redemption, such Market Participant, together with its group members, shall cease to beneficially own five percent or more of any class or series of capital stock of the corporation outstanding, after giving effect to such redemption.

The terms, conditions and procedures of any redemption pursuant to clause (e) of this Article VIII shall be as follows:

(1)           the redemption price of the shares of capital stock to be redeemed pursuant to this Article VIII shall be equal to the fair market value of such shares, as

7

determined by the Board of Directors in good faith; provided, however, that the fair market value of any shares of capital stock of a class or series that are listed on a U.S. securities exchange or quoted on an automated inter-dealer quotation system shall be equal to the lesser of (x) the Volume Weighted Average Price of such class or series for the 10 trading days immediately prior to the date on which a Redemption Notice (as defined in clause (3) below) is given by the corporation and (y) the Volume Weighted Average Price of such class or series for the 10 trading days immediately prior to the Redemption Date (as defined in clause (3) below), in each case as determined by the Board of Directors in good faith);

(2)           if less than all of the shares of capital stock of the corporation that are redeemable under this clause (e) are to be redeemed, then the shares to be redeemed shall be selected in any manner determined by the Board of Directors to be fair and equitable or in the best interests of the corporation’s shareholders;

(3)           at least 45 days’ prior written notice of the redemption, which notice shall specify the Volume Weighted Average Price referred to in clause (1)(x) above and the date of redemption (the “Redemption Date”), shall be given by the corporation to the holder(s) of record of the shares of capital stock to be redeemed (the “Redemption Notice”) (unless such 45-day period and/or notice shall be waived in writing by any such holder);

(4)           any shares of capital stock of the corporation which are the subject of the Redemption Notice shall cease to be redeemable if, prior to the fifth day before the Redemption Date, (A) the person or entity beneficially owning such shares on the date on which the Redemption Notice is given shall cease to beneficially own such shares and deliver written notice to the Secretary of the corporation to such effect, together with supporting documentation reasonably satisfactory to the Secretary or (B) the Board of Directors determines that such person or entity is not a Market Participant in accordance with the provisions of clause (b)(1) of this Article VIII;

(5)           without limiting any of the rights or remedies set forth in this Article VIII, from and after the Redemption Date, all shares redeemed on such date shall cease to be regarded as outstanding and any and all rights of the holder(s) in respect of such shares or attaching to such shares of whatever nature (including any rights to vote or participate in dividends declared on capital stock of the same class or series as such shares, excepting only payment of dividends declared prior to the Redemption Date for which the record date precedes the Redemption Date) shall cease and terminate, and the holder(s) thereof thereafter shall be entitled only to receive the cash or securities payable upon redemption; and

(6)           such other terms and conditions as the Board of Directors shall determine.

(f)            The Board of Directors and the officers of the corporation shall have all

8

powers necessary to implement the provisions of this Article VIII.

(g)           Each certificate representing shares of any class or series of capital stock of the corporation shall bear a legend substantially in the form set forth below, except as otherwise determined by the Board of Directors:

The corporation’s Amended and Restated Articles of Incorporation, as the same may be amended from time to time (the “Articles”), impose certain restrictions on the transfer, beneficial ownership and voting of the shares of capital stock represented by this certificate under certain circumstances if the holder or “beneficial owner” (as defined in the Articles) of the shares represented hereby (or, in the case of a transfer, by such holder’s transferee) is a “Market Participant” (as defined in the Articles) or member of a “group” (as defined in the Articles) with a Market Participant.  The Articles also permit the corporation’s board of directors to redeem the shares of capital stock beneficially owned by a Market Participant or member of a group with a Market Participant under certain circumstances.  At no charge, any holder of any class or series of capital stock of the corporation may receive a written statement of the restrictions imposed by the Articles.

(h)           If (i) any person or entity, together with its group members, shall have acquired beneficial ownership of five percent or more of any class or series of capital stock of the corporation and shall have made a filing with the SEC under Regulation 13D-G in respect of such beneficial ownership or (ii) any person or entity (other than a depositary institution or broker-dealer who is not a “beneficial owner” for purposes of Regulation 13D-G) is a record holder of five percent or more of any class or series of capital stock of the corporation, then such person or entity shall be entitled to deliver or, upon the written request from time to time by the Secretary of the corporation, shall promptly (and in no event later than 10 days thereafter) deliver, a written declaration to the Secretary of the corporation, which declaration (A) shall specify the number of shares of capital stock beneficially owned by such person or entity, together with its group members (including the name of the record holder of all such shares), and (B) include either (1) a certification by such person or entity that neither it, nor any of its group members, is a Market Participant or (2) a certified list of all such person’s or entity’s (together with all of its group members’) activities and investments related to the sale, marketing, trading, brokering or distribution of electric energy, or the provision of ancillary services to ITC or to the Regional Transmission Organization to which the corporation or its subsidiaries belong.  If the Secretary of the corporation shall deliver such a written request to a person or entity referred to in clauses (i) or (ii) above and such person or entity does not deliver a declaration to the corporation in accordance with this clause (h) within such 10-day period, such person or entity shall be deemed to be a Market Participant for purposes of this Article VIII, unless such person or entity subsequently delivers a declaration in accordance with this clause (h) and the Board of Directors subsequently makes a determination in accordance with clause (a)(1) of this Article VIII that such person or entity is not a Market Participant.  In making any determination under this Article VIII, the Board of Directors

9

shall be entitled to treat any statements set forth in a declaration delivered under this clause (h) to be prima facie evidence of the information set forth in such declaration.

(i)            Nothing contained in these Articles shall preclude the settlement of any transaction entered into through the facilities of the New York Stock Exchange or any other U.S. securities exchange or automated inter-dealer quotation system on which shares of capital stock may be listed or quoted from time to time.  The shares of capital stock that are the subject of such a transaction shall continue to be subject to the provisions of this Article VIII after any such settlement.  The fact that the settlement of any transaction is permitted shall not negate the effect of any other provision of this Article VIII and any transferee in such a transaction shall be subject to all of the provisions and limitations set forth in this Article VIII.

ARTICLE IX

Applicability of Chapter 7A

The corporation expressly elects not to be governed by Chapter 7A of the MBCA.

ARTICLE X

Amendments

The corporation reserves the right to adopt, repeal, alter or amend any provision of these Articles in the manner now or hereafter prescribed by the MBCA and all rights, preferences and privileges conferred on shareholders, directors, officers, employees, agents and other persons in these Articles, if any, are granted subject to this reservation (subject to the last sentence of Article V).

ADOPTION OF AMENDED AND RESTATED ARTICLES

These Amended and Restated Articles of Incorporation were duly adopted on the 27th day of May, 2005 in accordance with the provisions of Sections 611(3), 641(4) and 784(1)(b) of the MBCA and were duly adopted by the written consent of the shareholders entitled to vote in accordance with section 407(1) of the MBCA.  Written notice has been given to non-consenting shareholders as required by Section 407(1) of the MBCA.

	Signed this 13th day of June, 2005
By	/s/ Joseph L. Welch
	(Signature of an authorized officer or agent)
Joseph L. Welch		President & CEO
(Type or Print Name)		(Type or Print Title)

CERTIFICATE OF AMENDMENT TO THE

AMENDED AND RESTATED ARTICLES OF INCORPORATION OF

ITC HOLDINGS CORP.

(A Domestic Profit Corporation)

Pursuant to the provisions of Act 284, Public Acts of 1972, the undersigned corporation executes the following Certificate of Amendment:

1.    The present name of the corporation is:

ITC Holdings Corp.

2. The identification number assigned by the Bureau is 40595C.

3. Article III, Section 1 of the Amended and Restated Articles of Incorporation is hereby amended and restated in its entirety to read as follows:

ARTICLE III

Section 1. Authorized Shares. The total authorized shares of the corporation consists of 310,000,000 shares, 300,000,000 of which shall be Common Stock, with no par value (the “Common Stock”) and 10,000,000 of which shall be Preferred Stock, with no par value (the “Preferred Stock”).

* * * * * * * * * * * * * * * * * * * * *

The foregoing amendment to the Amended and Restated Articles of Incorporation proposed by the board was duly adopted on April 16, 2013 by the shareholders at a meeting in accordance with Section 611(3) of the Michigan Business Corporation Act.

Signed this 10^th day of January, 2014.

By:        /s/ Daniel J. Oginsky

Name:    Daniel J. Oginsky

Title:    Senior Vice President and General Counsel

EX-31.1

EXHIBIT 31.1

CERTIFICATION PURSUANT TO RULE 13A-14(A) OR 15D-14(A), AS ADOPTED PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Joseph L. Welch, certify that:

1. I have reviewed this annual report on Form 10-K of ITC Holdings Corp.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Dated: February 27, 2014

/s/ Joseph L. Welch

Joseph L. Welch

President and Chief Executive Officer

EX-31.2

EXHIBIT 31.2

CERTIFICATION PURSUANT TO RULE 13A-14(A) OR 15D-14(A), AS ADOPTED PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Cameron M. Bready, certify that:

1. I have reviewed this annual report on Form 10-K of ITC Holdings Corp.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Dated: February 27, 2014

/s/ Cameron M. Bready

Cameron M. Bready

Executive Vice President and Chief Financial Officer

EX-32

EXHIBIT 32

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of ITC Holdings Corp. (the “Registrant”) on Form 10-K for the period ended December 31, 2013 as filed with the Securities and Exchange Commission on February 27, 2014 (the “Report”), we, Joseph L. Welch, President and Chief Executive Officer of the Registrant, and Cameron M. Bready, Executive Vice President and Chief Financial Officer of the Registrant, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

Dated: February 27, 2014

/s/ Joseph L. Welch

Joseph L. Welch

President and Chief Executive Officer

/s/ Cameron M. Bready

Cameron M. Bready

Executive Vice President and Chief Financial Officer

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RETIREMENT BENEFITS AND ASSETS HELD IN TRUST (Tables)

12 Months Ended

Dec. 31, 2013

Retirement Plan

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block

Plan Assets By Category

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

Asset Category	2013		2012
Fixed income securities	47.7	%	48.4	%
Equity securities	52.3	%	51.6	%
Total	100.0	%	100.0	%

Assets Measured at Fair Value Subject to Three-Tier Hierarchy

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 fair value measurement of the retirement plan assets as of December 31, 2012, 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:
Pooled separate accounts — U.S. equity securities	$	—	$	15,702	$	—
Pooled separate accounts — international equity securities	—		3,979		—
Pooled separate accounts — fixed income securities	—		15,824		—
Guaranteed deposit fund	—		2,625		—
Total	$	—	$	38,130	$	—

Defined Benefit Plans

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block

Net Defined Benefit Cost Components

Net pension cost for 2013, 2012 and 2011 includes the following components:

(In thousands)	2013			2012			2011
Service cost	$	5,261		$	4,160		$	3,585
Interest cost	2,792			2,590			2,458
Expected return on plan assets	(2,868		)	(2,277		)	(1,896		)
Amortization of prior service credit	(42		)	(42		)	(42		)
Amortization of unrecognized loss	2,714			3,470			2,607
Net pension cost	$	7,857		$	7,901		$	6,712

Defined Benefit Plans Disclosures

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, 2013 and 2012:

(In thousands)	2013			2012
Change in Benefit Obligation:
Beginning projected benefit obligation	$	(72,400	)	$	(56,069	)
Service cost	(5,261		)	(4,160		)
Interest cost	(2,792		)	(2,590		)
Actuarial net gain (loss)	6,161			(10,481		)
Benefits paid	824			900
Ending projected benefit obligation	$	(73,468	)	$	(72,400	)
Change in Plans’ Assets:
Beginning plan assets at fair value	$	38,130		$	28,276
Actual return on plan assets	4,650			3,331
Employer contributions	6,938			7,023
Benefits paid	(824		)	(500		)
Ending plan assets at fair value	$	48,894		$	38,130
Funded status, underfunded	$	(24,574	)	$	(34,270	)
Accumulated benefit obligation	$	(61,832	)	$	(55,649	)
Amounts recorded as:
Funded Status:
Accrued pension liabilities	$	(35,003	)	$	(35,899	)
Pension assets — other assets — other	10,429			1,629
Total	$	(24,574	)	$	(34,270	)
Accumulated benefit obligation:
Qualified defined benefit retirement plan	$	(36,033	)	$	(33,051	)
Supplemental nonqualified retirement plans	(25,799		)	(22,598		)
Total	$	(61,832	)	$	(55,649	)
Unrecognized Amounts in Other Regulatory Assets:
Net actuarial loss	$	12,787		$	23,444
Prior service credit	(17		)	(59		)
Total	$	12,770		$	23,385

Assumptions Used

Actuarial assumptions used to determine the benefit obligation for 2013, 2012 and 2011 are listed below:

	2013	2012	2011
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%

Actuarial assumptions used to determine the benefit cost for 2013, 2012 and 2011 are listed below:

	2013	2012	2011
Discount rate	3.70 - 4.45%	4.50 - 5.00%	5.17 - 5.67%
Annual rate of salary increases	5.00 - 6.00%	5.00 - 6.00%	5.00 - 6.00%
Expected long-term rate of return on plan assets	7.00%	7.25%	7.25%

Projected Benefit Payments

At December 31, 2013, the projected benefit payments for the defined benefit retirement plans calculated using the same assumptions as those used to calculate the benefit obligation described above are listed below:

(In thousands)
2014	$	1,507
2015	1,762
2016	1,661
2017	5,250
2018	5,657
2019 through 2023	33,361

Other Postretirement Benefits Plan

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block

Plan Assets By Category

The plan assets consisted of the following assets by category:

Asset Category	2013		2012
Fixed income securities	46.6	%	49.8	%
Equity securities	53.4	%	50.2	%
Total	100.0	%	100.0	%

Net Defined Benefit Cost Components

Net postretirement cost for 2013, 2012 and 2011 includes the following components:

(In thousands)	2013			2012			2011
Service cost	$	5,774		$	5,433		$	3,431
Interest cost	1,562			1,552			1,285
Expected return on plan assets	(1,415		)	(1,016		)	(737		)
Amortization of prior service cost	—			125			313
Amortization of unrecognized loss	220			534			220
Net postretirement cost	$	6,141		$	6,628		$	4,512

Defined Benefit Plans Disclosures

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, 2013 and 2012:

(In thousands)	2013			2012
Change in Benefit Obligation:
Beginning accumulated postretirement obligation	$	(37,015	)	$	(30,679	)
Service cost	(5,774		)	(5,433		)
Interest cost	(1,562		)	(1,552		)
Actuarial net gain	1,491			474
Benefits paid	154			175
Ending accumulated postretirement obligation	$	(42,706	)	$	(37,015	)
Change in Plan’s Assets:
Beginning plan assets at fair value	$	19,670		$	13,549
Actual return on plan assets	2,857			1,747
Employer contributions	1,477			4,374
Employer provided retiree premiums	154			175
Benefits paid	(154		)	(175		)
Ending plan assets at fair value	$	24,004		$	19,670
Funded status, underfunded	$	(18,702	)	$	(17,345	)
Amounts recorded as:
Funded Status:
Accrued postretirement liabilities	$	(18,702	)	$	(17,345	)
Total	$	(18,702	)	$	(17,345	)
Unrecognized Amounts in Other Regulatory Assets:
Net actuarial loss	$	2,309		$	5,461
Prior service credit	—			—
Total	$	2,309		$	5,461

Assumptions Used

Actuarial assumptions used to determine the benefit obligation for 2013, 2012 and 2011 are as follows:

	2013	2012	2011
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
Annual rate of increase in dental benefit costs	5.00%	5.00%	5.00%

Actuarial assumptions used to determine the benefit cost for 2013, 2012 and 2011 are as follows:

	2013	2012	2011
Discount rate	4.20%	5.00%	5.49%
Annual rate of salary increases	5.00%	5.00%	5.00%
Health care cost trend rate assumed for next year	8.00%	9.00%	9.00%
Rate to which the cost trend rate is assumed to decline	5.00%	5.00%	5.00%
Expected long-term rate of return on plan assets	7.00%	7.25%	7.25%
Year that the rate reaches the ultimate trend rate	2017	2017	2017

Projected Benefit Payments

At December 31, 2013, 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 listed below:

(In thousands)
2014	$	376
2015	482
2016	599
2017	766
2018	1,184
2019 through 2023	12,401

Assets Measured at Fair Value Subject to Three-Tier Hierarchy

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	$	—

The fair value measurement of the other postretirement benefit plan assets as of December 31, 2012, 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	$	16	$	—	$	—
Pooled separate accounts — U.S. equity securities	—		2,131		—
Pooled separate accounts — international equity securities	—		529		—
Pooled separate accounts — fixed income securities	—		2,222		—
Mutual funds — equity securities	7,214		—		—
Mutual funds — fixed income securities	7,117		—		—
Guaranteed deposit fund	—		441		—
Total	$	14,347	$	5,323	$	—

Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates

A one-percentage-point increase or decrease in assumed health care cost trend rates would have the following effects on costs for 2013 and the postretirement benefit obligation at December 31, 2013:

	One-Percentage-		One-Percentage-
(In thousands)	Point Increase		Point Decrease
Effect on total of service and interest cost	$	1,400	$	(1,096	)
Effect on postretirement benefit obligation	7,449		(5,921		)

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REGULATORY ASSETS AND LIABILITIES Regulatory Liabilities (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Regulatory Liabilities
Regulatory liabilities — revenue deferrals, including accrued interest	$ 33,120	[1]	$ 53,763	[1]
Regulatory liabilities — revenue deferrals, including accrued interest	36,447	[1]	28,613	[1]
Regulatory liability	153,173		170,504
Accrued Interest on Revenue Deferrals
Regulatory Liabilities
Current regulatory liability	1,535	[1]	2,492	[1]
Regulatory liability	581	[1]	473	[1]
Accrued asset removal costs
Regulatory Liabilities
Regulatory liability	67,571		75,477
FERC Audit Refund
Regulatory Liabilities
Regulatory liability	13,067	[2]	12,651	[2]
Accrued Interest for FERC Refund
Regulatory Liabilities
Regulatory liability	2,095	[2]	1,679	[2]
Other
Regulatory Liabilities
Regulatory liability	$ 2,968	[3]	$ 0	[3]

[1] 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.

[2] Refer to discussion of FERC audit refund in Note 16 under “FERC Audit of ITC Midwest.” As of December 31, 2013 and 2012, the FERC audit refund was recorded in the consolidated statements of financial position in other current liabilities and other liabilities, respectively.

[3] As of December 31, 2013, amount was recorded in other liabilities in the consolidated statements of financial position.

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SIGNIFICANT ACCOUNTING POLICIES Supplementary Cash Flows Information (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Supplementary cash flows information:
Interest paid (net of interest capitalized)	$ 155,112		$ 148,598		$ 142,101
Income taxes paid — net	20,092		41,174		34,127
Supplementary non-cash investing and financing activities:
Additions to property, plant and equipment and other long-lived assets	68,276	[1]	94,218	[1]	102,091	[1]
Allowance for equity funds used during construction	$ 30,159		$ 23,000		$ 16,699

[1] 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, 2013, 2012 or 2011, respectively, but have been or will be included as a cash outflow from investing activities for expenditures for property, plant and equipment when paid.

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RETIREMENT BENEFITS AND ASSETS HELD IN TRUST Plan Assets By Category (Details)	Dec. 31, 2013	Dec. 31, 2012
Retirement Plan
Defined Benefit Plan Disclosure
Asset allocation	100.00%	100.00%
Other Postretirement Benefits Plan
Defined Benefit Plan Disclosure
Asset allocation	100.00%	100.00%
Fixed income securities | Retirement Plan
Defined Benefit Plan Disclosure
Asset allocation	47.70%	48.40%
Fixed income securities | Other Postretirement Benefits Plan
Defined Benefit Plan Disclosure
Asset allocation	46.60%	49.80%
Equity securities | Retirement Plan
Defined Benefit Plan Disclosure
Asset allocation	52.30%	51.60%
Equity securities | Other Postretirement Benefits Plan
Defined Benefit Plan Disclosure
Asset allocation	53.40%	50.20%

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REGULATORY ASSETS AND LIABILITIES Additional Information (Details) (USD $)						12 Months Ended				0 Months Ended	12 Months Ended				12 Months Ended				12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011 Michigan	Dec. 31, 2013 Revenue Accruals, Accrued Interest	Dec. 31, 2012 Revenue Accruals, Accrued Interest	Dec. 31, 2013 ITCTransmission ADIT Deferral	Dec. 31, 2012 ITCTransmission ADIT Deferral	Dec. 31, 2011 ITCTransmission ADIT Deferral	Feb. 28, 2003 ITCTransmission ADIT Deferral	Jan. 01, 2007 METC LLC ADIT Deferral	Dec. 31, 2013 METC LLC ADIT Deferral	Dec. 31, 2012 METC LLC ADIT Deferral	Dec. 31, 2011 METC LLC ADIT Deferral	Jan. 31, 2007 METC LLC ADIT Deferral	Dec. 31, 2013 METC LLC Regulatory Deferrals	Dec. 31, 2012 METC LLC Regulatory Deferrals	Dec. 31, 2011 METC LLC Regulatory Deferrals	Jan. 31, 2007 METC LLC Regulatory Deferrals	Dec. 31, 2013 ITC Great Plains LLC Start-up, Development and Pre-construction	Dec. 31, 2012 ITC Great Plains LLC Start-up, Development and Pre-construction
Regulatory Assets
Regulatory asset	$ 188,439,000	$ 190,586,000		$ 27,000	$ 17,000	$ 27,776,000	$ 30,806,000		$ 60,600,000		$ 25,945,000	$ 28,304,000		$ 42,500,000	$ 10,029,000	$ 10,800,000		$ 15,400,000	$ 13,916,000	$ 14,117,000
Regulatory asset, amortization period (in years)						20				18					20				10
Amortization expense						3,000,000	3,000,000	3,000,000			2,400,000	2,400,000	2,400,000		800,000	800,000	800,000
Equity component of carrying charges																			$ 8,200,000
State income tax rate			6.00%

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FAIR VALUE MEASUREMENTS Assets Measured at Fair Value Subject to Three-Tier Hierarchy (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring Basis
Fair value, level transfers	$ 0	$ 0
Recurring Basis | Fair Value Measurements at Reporting Date Using Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring Basis
Total - assets	40,834	36,071
Recurring Basis | Fair Value Measurements at Reporting Date Using Quoted Prices in Active Markets for Identical Assets (Level 1) | Cash Equivalents
Fair Value, Assets and Liabilities Measured on Recurring Basis
Cash and cash equivalents	19,000	13,127
Recurring Basis | Fair Value Measurements at Reporting Date Using Quoted Prices in Active Markets for Identical Assets (Level 1) | Fixed Income Securities
Fair Value, Assets and Liabilities Measured on Recurring Basis
Mutual funds	21,318	21,332
Recurring Basis | Fair Value Measurements at Reporting Date Using Quoted Prices in Active Markets for Identical Assets (Level 1) | Equity securities
Fair Value, Assets and Liabilities Measured on Recurring Basis
Mutual funds	516	1,612
Recurring Basis | Fair Value Measurements at Reporting Date Using Significant Other Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring Basis
Total - net liabilities		(18,745)
Recurring Basis | Fair Value Measurements at Reporting Date Using Significant Other Observable Inputs (Level 2) | Cash Equivalents
Fair Value, Assets and Liabilities Measured on Recurring Basis
Cash and cash equivalents		10,037
Recurring Basis | Fair Value Measurements at Reporting Date Using Significant Other Observable Inputs (Level 2) | Interest Rate Swaps
Fair Value, Assets and Liabilities Measured on Recurring Basis
Interest rate swap derivatives - asset		2,725
Interest rate swap derivatives - liability		$ (31,507)

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SUPPLEMENTARY QUARTERLY FINANCIAL INFORMATION (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2013

Selected Quarterly Financial Information [Abstract]

Schedule of Supplementary Quarterly Financial Information (Unaudited)

	First		Second		Third		Fourth
(In thousands, except per share data)	Quarter		Quarter		Quarter		Quarter		Year
2013 (a)
Operating revenues	$	217,304	$	229,817	$	238,782	$	255,369	$	941,272
Operating income	112,881		110,994		130,822		141,364		496,061
Net income (b)	50,190		47,395		58,984		76,937		233,506
Basic earnings per share	$	0.96	$	0.90	$	1.12	$	1.47	$	4.46
Diluted earnings per share	$	0.95	$	0.90	$	1.12	$	1.45	$	4.42
2012 (a)
Operating revenues	$	196,713	$	197,375	$	214,801	$	221,646	$	830,535
Operating income	105,894		98,483		113,354		113,328		431,059
Net income	46,051		42,386		51,183		48,256		187,876
Basic earnings per share	$	0.90	$	0.82	$	0.99	$	0.93	$	3.65
Diluted earnings per share	$	0.88	$	0.81	$	0.98	$	0.92	$	3.60

____________________________

(a) During the years ended December 31, 2013 and 2012, we expensed external legal, advisory and financial services fees of $43.1 million and $19.4 million, respectively, and internal labor and related costs of approximately $7.8 million and $7.1 million, respectively, related to the Entergy Transaction. 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.

(b) 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 for the external costs related to the Entergy transaction incurred in 2013, 2012 and 2011 that originally were recorded as non-deductible for income tax provision purposes.

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REGULATORY ASSETS AND LIABILITIES (Tables)

12 Months Ended

Dec. 31, 2013

Regulatory Assets and Liabilities Disclosure [Abstract]

Schedule of Regulatory Assets

The following table summarizes the regulatory asset balances at December 31, 2013 and 2012:

(In thousands)	2013		2012
Regulatory Assets:
Revenue accruals:
Current (including accrued interest of $114 and $131 as of December 31, 2013 and 2012, respectively)	$	6,334	$	7,489
Non-current (including accrued interest of $27 and $17 as of December 31, 2013 and 2012, respectively)	3,037		2,719
Other:
ITCTransmission ADIT Deferral (net of accumulated amortization of $32,826 and $29,796 as of December 31, 2013 and 2012, respectively)	27,776		30,806
METC ADIT Deferral (net of accumulated amortization of $16,511 and $14,152 as of December 31, 2013 and 2012, respectively)	25,945		28,304
METC Regulatory Deferrals (net of accumulated amortization of $5,400 and $4,628 as of December 31, 2013 and 2012, respectively)	10,029		10,800
Income taxes recoverable related to AFUDC equity	75,798		57,135
ITC Great Plains start-up, development and pre-construction	13,916		14,117
Pensions and postretirement	15,079		28,847
Income taxes recoverable related to implementation of the Michigan Corporate Income Tax	8,869		8,869
Other	1,656		1,500
Total	$	188,439	$	190,586

Schedule of Regulatory Liabilities

The following table summarizes the regulatory liability balances at December 31, 2013 and 2012:

(In thousands)	2013		2012
Regulatory Liabilities:
Revenue deferrals (a):
Current (including accrued interest of $1,535 and $2,492 as of December 31, 2013 and 2012, respectively)	$	33,120	$	53,763
Non-current (including accrued interest of $581 and $473 as of December 31, 2013 and 2012, respectively)	36,447		28,613
Accrued asset removal costs	67,571		75,477
FERC audit refund (including accrued interest of $2,095 and $1,679 as of December 31, 2013 and 2012, respectively) (b)	13,067		12,651
Other (c)	2,968		—
Total	$	153,173	$	170,504

____________________________

(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.” As of December 31, 2013 and 2012, the FERC audit refund was recorded in the consolidated statements of financial position in other current liabilities and other liabilities, respectively.

(c) As of December 31, 2013, amount was recorded in other liabilities in the consolidated statements of financial position.

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FAIR VALUE MEASUREMENTS Additional Information (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Fair Value Disclosures [Abstract]
Fair value of long-term debt and debt maturing within one year, excluding revolving and term loan credit agreements	$ 3,299.0	$ 3,072.9
Book value of long-term debt and debt maturing within one year, excluding revolving and term loan credit agreements	3,100.9	2,619.4
Book value of revolving and term loan credit agreements	$ 511.2	$ 527.8

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RETIREMENT BENEFITS AND ASSETS HELD IN TRUST Assumptions Used (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plans
Benefit Cost Assumptions
Expected long-term rate of return on plan assets	7.00%	7.25%	7.25%
Defined Benefit Plans | Minimum
Benefit Obligation Assumptions
Discount rate	4.60%	3.70%	4.50%
Annual rate of salary increases	4.00%	5.00%	5.00%
Benefit Cost Assumptions
Discount rate	3.70%	4.50%	5.17%
Annual rate of salary increases	5.00%	5.00%	5.00%
Defined Benefit Plans | Maximum
Benefit Obligation Assumptions
Discount rate	5.10%	4.45%	5.00%
Annual rate of salary increases	6.00%	6.00%	6.00%
Benefit Cost Assumptions
Discount rate	4.45%	5.00%	5.67%
Annual rate of salary increases	6.00%	6.00%	6.00%
Other Postretirement Benefits Plan
Benefit Obligation Assumptions
Discount rate	5.15%	4.20%	5.00%
Annual rate of salary increases	4.00%	5.00%	5.00%
Benefit Cost Assumptions
Discount rate	4.20%	5.00%	5.49%
Annual rate of salary increases	5.00%	5.00%	5.00%
Other Postretirement Benefits Plan | Benefit Obligation
Assumed Health Care Cost Trend Rates
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
Annual rate of increase in dental benefit costs	5.00%	5.00%	5.00%
Other Postretirement Benefits Plan | Benefit Cost
Benefit Cost Assumptions
Expected long-term rate of return on plan assets	7.00%	7.25%	7.25%
Assumed Health Care Cost Trend Rates
Health care cost trend rate assumed for next year	8.00%	9.00%	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	2017	2017	2017

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ENTERGY TRANSACTION (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
External Legal, Advisory and Financial Services Fees
Terminated Entergy Transaction
Entergy Transaction related expenses	$ 43.1	$ 19.4	$ 7.0
Internal Labor and Associated Costs
Terminated Entergy Transaction
Entergy Transaction related expenses	$ 7.8	$ 7.1	$ 1.6

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GOODWILL AND INTANGIBLE ASSETS Future Amortization Expense (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Future Amortization Expense
2014	$ 3,276
2015	3,276
2016	3,276
2017	3,276
2018	3,276
2019 and thereafter	32,948
Total	$ 49,328	$ 48,492

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RETIREMENT BENEFITS AND ASSETS HELD IN TRUST Assets Measured at Fair Value Subject to Three-Tier Heirarchy (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan Disclosure
Fair value, level transfers	$ 0	$ 0
Retirement Plan
Defined Benefit Plan Disclosure
Fair value, level transfers	0	0
Other Postretirement Benefits Plan
Defined Benefit Plan Disclosure
Fair value, level transfers	0	0
Fair value amount	24,004	19,670	13,549
Recurring Basis | Retirement Plan | Fair Value Measurements at Reporting Date Using Quoted Prices in Active Markets for Identical Assets (Level 1)
Defined Benefit Plan Disclosure
Fair value amount	45,408
Recurring Basis | Retirement Plan | Fair Value Measurements at Reporting Date Using Quoted Prices in Active Markets for Identical Assets (Level 1) | U.S. equity securities
Defined Benefit Plan Disclosure
Fair value amount	20,639
Recurring Basis | Retirement Plan | Fair Value Measurements at Reporting Date Using Quoted Prices in Active Markets for Identical Assets (Level 1) | International equity securities
Defined Benefit Plan Disclosure
Fair value amount	4,956
Recurring Basis | Retirement Plan | Fair Value Measurements at Reporting Date Using Quoted Prices in Active Markets for Identical Assets (Level 1) | Fixed income securities
Defined Benefit Plan Disclosure
Fair value amount	19,813
Recurring Basis | Retirement Plan | Fair Value Measurements at Reporting Date Using Significant Other Observable Inputs (Level 2)
Defined Benefit Plan Disclosure
Fair value amount	3,486	38,130
Recurring Basis | Retirement Plan | Fair Value Measurements at Reporting Date Using Significant Other Observable Inputs (Level 2) | U.S. equity securities
Defined Benefit Plan Disclosure
Fair value amount		15,702
Recurring Basis | Retirement Plan | Fair Value Measurements at Reporting Date Using Significant Other Observable Inputs (Level 2) | International equity securities
Defined Benefit Plan Disclosure
Fair value amount		3,979
Recurring Basis | Retirement Plan | Fair Value Measurements at Reporting Date Using Significant Other Observable Inputs (Level 2) | Fixed income securities
Defined Benefit Plan Disclosure
Fair value amount		15,824
Recurring Basis | Retirement Plan | Fair Value Measurements at Reporting Date Using Significant Other Observable Inputs (Level 2) | Guaranteed deposit fund
Defined Benefit Plan Disclosure
Fair value amount	3,486	2,625
Recurring Basis | Other Postretirement Benefits Plan | Fair Value Measurements at Reporting Date Using Quoted Prices in Active Markets for Identical Assets (Level 1)
Defined Benefit Plan Disclosure
Fair value amount	23,472	14,347
Recurring Basis | Other Postretirement Benefits Plan | Fair Value Measurements at Reporting Date Using Quoted Prices in Active Markets for Identical Assets (Level 1) | Cash and Cash Equivalents
Defined Benefit Plan Disclosure
Fair value amount	519	16
Recurring Basis | Other Postretirement Benefits Plan | Fair Value Measurements at Reporting Date Using Quoted Prices in Active Markets for Identical Assets (Level 1) | U.S. equity securities
Defined Benefit Plan Disclosure
Fair value amount	12,113
Recurring Basis | Other Postretirement Benefits Plan | Fair Value Measurements at Reporting Date Using Quoted Prices in Active Markets for Identical Assets (Level 1) | International equity securities
Defined Benefit Plan Disclosure
Fair value amount	713
Recurring Basis | Other Postretirement Benefits Plan | Fair Value Measurements at Reporting Date Using Quoted Prices in Active Markets for Identical Assets (Level 1) | Fixed income securities
Defined Benefit Plan Disclosure
Fair value amount	10,127	7,117
Recurring Basis | Other Postretirement Benefits Plan | Fair Value Measurements at Reporting Date Using Quoted Prices in Active Markets for Identical Assets (Level 1) | Equity securities
Defined Benefit Plan Disclosure
Fair value amount		7,214
Recurring Basis | Other Postretirement Benefits Plan | Fair Value Measurements at Reporting Date Using Significant Other Observable Inputs (Level 2)
Defined Benefit Plan Disclosure
Fair value amount	532	5,323
Recurring Basis | Other Postretirement Benefits Plan | Fair Value Measurements at Reporting Date Using Significant Other Observable Inputs (Level 2) | U.S. equity securities
Defined Benefit Plan Disclosure
Fair value amount		2,131
Recurring Basis | Other Postretirement Benefits Plan | Fair Value Measurements at Reporting Date Using Significant Other Observable Inputs (Level 2) | International equity securities
Defined Benefit Plan Disclosure
Fair value amount		529
Recurring Basis | Other Postretirement Benefits Plan | Fair Value Measurements at Reporting Date Using Significant Other Observable Inputs (Level 2) | Fixed income securities
Defined Benefit Plan Disclosure
Fair value amount		2,222
Recurring Basis | Other Postretirement Benefits Plan | Fair Value Measurements at Reporting Date Using Significant Other Observable Inputs (Level 2) | Guaranteed deposit fund
Defined Benefit Plan Disclosure
Fair value amount	$ 532	$ 441

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JOINTLY OWNED UTILITY PLANT/COORDINATED SERVICES Schedule of Jointly Owned Utility Plant (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013
Jointly Owned Utility Plant Interests
Net investment	$ 120,502	[1]
Construction work in progress	6,686
Substations
Jointly Owned Utility Plant Interests
Net investment	27,345	[1]
Construction work in progress	3,461
Lines
Jointly Owned Utility Plant Interests
Net investment	93,157	[1]
Construction work in progress	$ 3,225

[1] Amount represents our investment in jointly held plant, which has been reduced by the ownership interest amounts of other parties.

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STOCKHOLDERS EQUITY Additional Information (Details) (USD $)							12 Months Ended				12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013 Sales Agency Financing Agreement	Jul. 27, 2011 Sales Agency Financing Agreement	Jul. 27, 2011 Maximum Sales Agency Financing Agreement	Jan. 10, 2014 Subsequent Event	Dec. 31, 2013 Common Stock	Dec. 31, 2012 Common Stock	Dec. 31, 2011 Common Stock	Dec. 31, 2010 Common Stock	Dec. 31, 2013 Common Stock	Dec. 31, 2012 Common Stock	Dec. 31, 2011 Common Stock
Class of Stock [Line Items]
Common stock, shares authorized	100,000,000	100,000,000				300,000,000
Common stock, par value	$ 0			$ 0		$ 0
Preferred stock, authorized shares	10,000,000
Preferred stock, par value	$ 0
Common stock, shares outstanding	52,500,265	52,248,514					52,500,265	52,248,514	51,323,368	50,715,805
Preferred stock, outstanding shares	0
Common stock, shareholders of record	695
Shares issued of preferred stock	0
FERC approved capital structure, equity percentage	60.00%
FERC approved capital structure, debt percentage	40.00%
Repurchase and retirement of common stock, shares							54,440	99,533	89,715		54,440	99,533	89,715
Repurchase and retirement of common stock							$ 4,885,000	$ 7,266,000	$ 6,401,000		$ 4,900,000	$ 7,300,000	$ 6,400,000
Common stock issuable shares value				$ 250,000,000
Commission rate					2.00%
Common stock, shares issued	52,500,265	52,248,514	0

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JOINTLY OWNED UTILITY PLANT/COORDINATED SERVICES Additional Information (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013
Michigan Public Power Agency | Lines
Jointly Owned Utility Plant Interests
Ownership percentage	50.40%
ITCTransmission | Lines
Jointly Owned Utility Plant Interests
Number of transmission lines	2
Net investment including assets under construction	$ 25.1
METC LLC | Substations
Jointly Owned Utility Plant Interests
Net investment including assets under construction	13.3
METC LLC | Substations | Minimum
Jointly Owned Utility Plant Interests
Ownership percentage	6.30%
METC LLC | Substations | Maximum
Jointly Owned Utility Plant Interests
Ownership percentage	92.00%
METC LLC | Lines
Jointly Owned Utility Plant Interests
Net investment including assets under construction	41.1
METC LLC | Lines | Minimum
Jointly Owned Utility Plant Interests
Ownership percentage	35.50%
METC LLC | Lines | Maximum
Jointly Owned Utility Plant Interests
Ownership percentage	64.80%
ITC Midwest LLC | Substations
Jointly Owned Utility Plant Interests
Net investment including assets under construction	17.5
ITC Midwest LLC | Substations | Minimum
Jointly Owned Utility Plant Interests
Ownership percentage	28.00%
ITC Midwest LLC | Substations | Maximum
Jointly Owned Utility Plant Interests
Ownership percentage	80.00%
ITC Midwest LLC | Lines
Jointly Owned Utility Plant Interests
Net investment including assets under construction	$ 30.3
ITC Midwest LLC | Lines | Minimum
Jointly Owned Utility Plant Interests
Ownership percentage	48.00%
ITC Midwest LLC | Lines | Maximum
Jointly Owned Utility Plant Interests
Ownership percentage	80.00%

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RETIREMENT BENEFITS AND ASSETS HELD IN TRUST Additional Information (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Retirement Benefits Disclosure
Unrealized gains recognized in accumulated other comprehensive income	$ 71,000	$ 0	$ 0
Retirement Plan
Retirement Benefits Disclosure
Employer contributions	6,900,000	7,000,000	3,600,000
Retirement Plan | Expectation
Retirement Benefits Disclosure
Expected contribution	8,600,000
Supplemental Benefit Plans
Retirement Benefits Disclosure
Employer contributions	600,000	4,700,000	3,100,000
Net realized and unrealized gain (loss) recognized in other income (expense)	(1,800,000)	1,900,000	2,200,000
Unrealized gains recognized in accumulated other comprehensive income	100,000
Plan assets	21,100,000	22,400,000
Defined Benefit Plans
Retirement Benefits Disclosure
Employer contributions	6,938,000	7,023,000
Plan assets	10,429,000	1,629,000
Other Postretirement Benefits Plan
Retirement Benefits Disclosure
Employer contributions	1,477,000	4,374,000	3,400,000
Other Postretirement Benefits Plan | Expectation
Retirement Benefits Disclosure
Expected contribution	3,000,000
Defined Contribution Plan
Retirement Benefits Disclosure
Employer match contribution	$ 4,500,000	$ 3,800,000	$ 3,400,000

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RETIREMENT BENEFITS AND ASSETS HELD IN TRUST Net Defined Benefit Cost Components (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plans
Defined Benefit Plan Disclosure
Service cost	$ 5,261	$ 4,160	$ 3,585
Interest cost	2,792	2,590	2,458
Expected return on plan assets	(2,868)	(2,277)	(1,896)
Amortization of prior service cost (credit)	(42)	(42)	(42)
Amortization of unrecognized loss	2,714	3,470	2,607
Net cost	7,857	7,901	6,712
Other Postretirement Benefits Plan
Defined Benefit Plan Disclosure
Service cost	5,774	5,433	3,431
Interest cost	1,562	1,552	1,285
Expected return on plan assets	(1,415)	(1,016)	(737)
Amortization of prior service cost (credit)	0	125	313
Amortization of unrecognized loss	220	534	220
Net cost	$ 6,141	$ 6,628	$ 4,512

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ENTERGY TRANSACTION

12 Months Ended

Dec. 31, 2013

Business Combinations [Abstract]

ENTERGY TRANSACTION

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, 2013, 2012 and 2011, we expensed external legal, advisory and financial services fees related to the terminated Entergy Transaction of $43.1 million, $19.4 million and $7.0 million, respectively, and certain internal labor and associated costs related to the terminated Entergy Transaction of $7.8 million, $7.1 million and $1.6 million, respectively. Certain of the external costs were not deductible for income tax purposes for the years ended December 31, 2012 and 2011, but the costs incurred to date are deductible for the year ended December 31, 2013 upon the cancellation of the transaction. 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.

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REGULATORY MATTERS Changes in Regulatory Assets and Liabilities (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013
Revenue Accruals and Deferrals
Beginning balance	$ (72,168)
Net refund of 2011 revenue deferrals and accruals, including accrued interest	47,061
Net revenue deferral for the year ended December 31, 2013	(32,782)
Net accrued interest payable for the year ended December 31, 2013	(2,307)
Ending balance	$ (60,196)

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SHARE-BASED COMPENSATION (Tables)

12 Months Ended

Dec. 31, 2013

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Schedule of Share-based Compensation Cost Allocation

We recorded share-based compensation in 2013, 2012 and 2011 as follows:

(In thousands)	2013		2012		2011
Operation and maintenance expenses	$	1,617	$	1,933	$	2,540
General and administrative expenses	9,318		8,057		7,524
Amounts capitalized to property, plant and equipment	4,731		5,632		5,327
Total share-based compensation	$	15,666	$	15,622	$	15,391
Total tax benefit recognized in the consolidated statement of operations	$	4,557	$	3,807	$	3,976

Schedule of Stock Options Activity

Stock option activity for 2013 was as follows:

			Weighted
	Number of		Average
	Options		Exercise Price
Outstanding at January 1, 2013 (1,030,594 exercisable with a weighted average exercise price of $38.10)	1,603,429		$	49.02
Granted	310,111		87.93
Exercised	(166,338	)	49.09
Forfeited	(23,926	)	79.03
Outstanding at December 31, 2013 (1,128,540 exercisable with a weighted average exercise price of $42.98)	1,723,276		$	55.60

Schedule of Stock Options Valuation Assumptions

The following assumptions were used in determining the weighted average fair value per option:

	2013			2012			2011
	Option Grants			Option Grants			Option Grants
Weighted average grant date fair value per option	$	21.17		$	16.58		$	18.77
Weighted average expected volatility (a)	29.3		%	29.8		%	29.8		%
Weighted average risk-free interest rate	1.1		%	1.0		%	2.1		%
Weighted average expected term (b)	6 years			6 years			6 years
Weighted average expected dividend yield	1.72		%	1.99		%	1.86		%
Estimated fair value of underlying shares	$	87.93		$	70.76		$	72.15

____________________________

(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.

Schedule of Restricted Stock Activity

Restricted stock award activity for 2013 was as follows:

	Number of		Weighted
	Restricted		Average
	Stock		Grant Date
	Awards		Fair Value
Unvested restricted stock awards at January 1, 2013	523,350		$	62.63
Granted	128,192		88.27
Vested	(175,182	)	52.99
Forfeited	(14,038	)	76.13
Unvested restricted stock awards at December 31, 2013	462,322		$	72.97

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RETIREMENT BENEFITS AND ASSETS HELD IN TRUST Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates (Details) (Other Postretirement Benefits Plan, USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013
Other Postretirement Benefits Plan
Defined Benefit Plan Disclosure
Effect on total of service and interest cost, one percentage point increase	$ 1,400
Effect on total of service and interest cost, one percentage point decrease	(1,096)
Effect on postretirement benefit obligation, one percentage point increase	7,449
Effect on postretirement benefit obligation, one percentage point decrease	$ (5,921)

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SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT General (Details)	Dec. 31, 2013
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
FERC approved capital structure, equity percentage	60.00%
FERC approved capital structure, debt percentage	40.00%

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EARNINGS PER SHARE (Tables)

12 Months Ended

Dec. 31, 2013

Earnings Per Share, Basic and Diluted [Abstract]

Computation of Basic and Diluted Earnings Per Common Share

A reconciliation of both calculations for the years ended December 31, 2013, 2012 and 2011 is presented in the following table:

	Year Ended December 31,
(In thousands, except per share and share data)	2013			2012			2011
Numerator:
Net income	$	233,506		$	187,876		$	171,685
Less: dividends declared — common and restricted shares	(84,104		)	(75,124		)	(70,305		)
Undistributed earnings	149,402			112,752			101,380
Percentage allocated to common shares (a)	99.1		%	98.7		%	98.3		%
Undistributed earnings — common shares	148,057			111,286			99,657
Add: dividends declared — common shares	83,351			74,202			69,200
Numerator for basic and diluted earnings per common share	$	231,408		$	185,488		$	168,857
Denominator:
Denominator for basic earnings per common share — weighted average common shares	51,912,128			50,820,838			50,289,905
Incremental shares for stock options and employee stock purchase plan — weighted average assumed conversion	429,540			742,557			788,918
Denominator for diluted earnings per common share — adjusted weighted average shares and assumed conversion	52,341,668			51,563,395			51,078,823
Per common share net income:
Basic	$	4.46		$	3.65		$	3.36
Diluted	$	4.42		$	3.60		$	3.31

____________________________

(a)	Weighted average common shares outstanding	51,912,128		50,820,838		50,289,905
	Weighted average restricted shares and deferred stock units
	(participating securities)	490,989		658,835		854,717
	Total	52,403,117		51,479,673		51,144,622
	Percentage allocated to common shares	99.1	%	98.7	%	98.3	%

Schedule of Anti-dilutive Stock Options and ESPP Shares

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:

	2013	2012	2011
Outstanding stock options and ESPP shares (as of December 31)	1,723,276	1,603,429	2,100,056
Anti-dilutive stock options and ESPP shares (for the year ended December 31)	304,190	565,945	213,917

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REGULATORY MATTERS Additional Information (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Regulatory Matters
Regulatory asset	$ 188,439,000	$ 190,586,000
FERC approved capital structure, equity percentage	60.00%
Transmission rate, applicable period	1 year
Revenue true-up amount reflected in customer bill, period of recognition	2 years
ITC Great Plains LLC | Start-up, Development and Pre-construction
Regulatory Matters
Regulatory asset	13,916,000	14,117,000
Regulatory asset, amortization period (in years)	10
ITCTransmission
Regulatory Matters
Rate of return on equity	12.38%
ITCTransmission | Rate of Return on Equity and Capital Structure Complaint
Regulatory Matters
Rate of return on equity	9.15%
Complaint capital structure, equity percentage	50.00%
FERC approved capital structure, equity percentage	60.00%
METC LLC
Regulatory Matters
Rate of return on equity	12.38%
METC LLC | Rate of Return on Equity and Capital Structure Complaint
Regulatory Matters
Rate of return on equity	9.15%
Complaint capital structure, equity percentage	50.00%
FERC approved capital structure, equity percentage	60.00%
ITC Midwest LLC
Regulatory Matters
Rate of return on equity	12.38%
Rate discount period	8 years
ITC Midwest LLC | Rate Discount
Regulatory Matters
Rate discount	$ 4,100,000
ITC Midwest LLC | Rate of Return on Equity and Capital Structure Complaint
Regulatory Matters
Rate of return on equity	9.15%
Complaint capital structure, equity percentage	50.00%
FERC approved capital structure, equity percentage	60.00%

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INCOME TAXES Components of Income Tax Provision (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Components of Income Tax Provision
Current income tax expense	$ 42,159	$ 41,347	$ 63,952
Deferred income tax expense	76,094	66,710	33,266
Benefits of operating loss carryforward	609	575	2,169
Change in Michigan tax law	0	0	(4,638)
Total income tax provision	$ 118,862	$ 108,632	$ 94,749

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DEBT Interest Rate Swap Agreements (Details) (USD $) In Millions, unless otherwise specified		6 Months Ended	0 Months Ended	6 Months Ended	0 Months Ended	6 Months Ended
	Dec. 31, 2013	Jun. 30, 2013 Interest Rate Swap	Dec. 31, 2012 Interest Rate Swap 10-year	Jun. 30, 2013 Interest Rate Swap 10-year	Dec. 31, 2012 Interest Rate Swap 30-year	Jun. 30, 2013 Interest Rate Swap 30-year
Interest Rate Swaps
Notional amount	$ 0	$ 475.0	$ 175.0	$ 250.0	$ 50.0	$ 225.0
Term of contract			10 years	10 years	30 years	30 years
Weighted average fixed rate			3.99%	3.39%	2.59%	2.84%
Loss on derivatives				(15.0)
Gain on derivatives						26.2
Net gain on derivatives		$ 11.2

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SUBSEQUENT EVENTS (Tables)

12 Months Ended

Dec. 31, 2013

Subsequent Events [Abstract]

Schedule of Pro Forma Impact of Stock Split on Stockholders' Equity

The estimated pro forma impact of the stock split on our stockholders’ equity at December 31, 2013 is presented in the following table:

	Historical				Pro Forma
	December 31, 2013		Adjustment		December 31, 2013
(In thousands, except share data)	(Audited)		(Unaudited)		(Unaudited)
Common stock, without par value, 100,000,000 shares authorized, 52,500,265 shares issued and outstanding at December 31, 2013 (a)	$	1,014,435	$	—	$	1,014,435
Retained earnings	592,970		—		592,970
Accumulated other comprehensive income	6,327		—		6,327
Total stockholders’ equity	$	1,613,732	$	—	$	1,613,732

____________________________

(a) If the stock split had been paid at December 31, 2013, it would have increased the shares issued and outstanding on that date to 157,500,795. Authorized shares increased in January 2014 upon filing an amendment to the Articles of Incorporation with the State of Michigan.

Schedule of Pro Forma Impact of Stock Split on Earnings Per Share

The following table provides the estimated pro forma effects on our earnings per share, as calculated in Note 9, for the year ended December 31, 2013:

	Historical					Pro Forma
	December 31, 2013		Adjustment			December 31, 2013
(In thousands, except per share and share data)	(Audited)		(Unaudited)			(Unaudited)
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
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

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GENERAL

12 Months Ended

Dec. 31, 2013

Organization, Consolidation and Presentation of Financial Statements [Abstract]

GENERAL

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 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 Midwest Independent Transmission 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.

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DEBT Revolving Credit Agreements (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Line of Credit Facility
Total available capacity	$ 725,000,000
Outstanding balance	271,200,000	[1]
Unused capacity	453,800,000
ITC Holdings Corp.
Line of Credit Facility
Total available capacity	200,000,000
Outstanding balance	0	[1]
Unused capacity	200,000,000
Weighted average interest rate	0.00%	[2]
Commitment fee rate	0.20%	[3]
Original term	5 years
Interest rate description	Amounts outstanding would bear interest at a rate equal to LIBOR plus an applicable margin of 1.50% or at a base rate, which is defined as the higher of the prime rate, 0.50% above the federal funds rate or 1% above the one month LIBOR, plus an applicable margin of 0.50%, subject to adjustments based on ITC Holdings’ credit rating.
ITCTransmission
Line of Credit Facility
Total available capacity	100,000,000
Outstanding balance	41,100,000	[1]
Unused capacity	58,900,000
Weighted average interest rate	1.30%
Commitment fee rate	0.125%	[3]
Original term	5 years
METC LLC
Line of Credit Facility
Total available capacity	100,000,000
Outstanding balance	67,200,000	[1]
Unused capacity	32,800,000
Weighted average interest rate	1.30%
Commitment fee rate	0.125%	[3]
Original term	5 years
ITC Midwest LLC
Line of Credit Facility
Total available capacity	175,000,000
Outstanding balance	111,000,000	[1]
Unused capacity	64,000,000
Weighted average interest rate	1.20%
Commitment fee rate	0.10%	[3]
Original term	5 years
ITC Great Plains LLC
Line of Credit Facility
Total available capacity	150,000,000
Outstanding balance	51,900,000	[1]
Unused capacity	$ 98,100,000
Weighted average interest rate	1.90%
Commitment fee rate	0.25%	[3]
Original term	4 years

[1] Included within long-term debt.

[2] Amounts outstanding would bear interest at a rate equal to LIBOR plus an applicable margin of 1.50% or at a base rate, which is defined as the higher of the prime rate, 0.50% above the federal funds rate or 1% above the one month LIBOR, plus an applicable margin of 0.50%, subject to adjustments based on ITC Holdings’ credit rating.

[3] Calculation based on the average daily unused commitments, subject to adjustment based on the borrower’s credit rating.

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JOINTLY OWNED UTILITY PLANT/COORDINATED SERVICES (Tables)

12 Months Ended

Dec. 31, 2013

Regulated Operations [Abstract]

Schedule of Jointly Owned Utility Plant

We have investments in jointly owned utility assets as shown in the table below as of December 31, 2013:

	Net		Construction
(In thousands)	Investments (a)		Work in Progress
Substations	$	27,345	$	3,461
Lines	93,157		3,225
Total	$	120,502	$	6,686

____________________________

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

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SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT

12 Months Ended

Dec. 31, 2013

Condensed Financial Information of Parent Company Only Disclosure [Abstract]

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)	2013		2012
ASSETS
Current assets
Cash and cash equivalents	$	26,853	$	22,546
Accounts receivable from subsidiaries	50,196		51,005
Prepaid assets	5,806		22,756
Other	1,496		4,775
Total current assets	84,351		101,082
Other assets
Investment in subsidiaries	3,450,989		3,052,902
Deferred income taxes	25,519		35,272
Deferred financing fees (net of accumulated amortization of $6,346 and $8,063, respectively)	11,241		7,308
Other	47,660		55,393
Total other assets	3,535,409		3,150,875
TOTAL ASSETS	$	3,619,760	$	3,251,957
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	6,300	$	8,594
Accrued payroll	21,930		20,740
Accrued interest	37,486		30,985
Derivative instruments	—		31,507
Debt maturing within one year	50,000		466,935
Other	3,583		1,484
Total current liabilities	119,299		560,245
Accrued pension and postretirement liabilities	53,704		53,243
Other	1,106		930
Long-term debt (net of discounts of $3,082 and $1,916, respectively)	1,831,918		1,222,684
STOCKHOLDERS’ EQUITY
Common stock, without par value, 100,000,000 shares authorized, 52,500,265 and 52,248,514 shares issued and outstanding at December 31, 2013 and 2012, respectively	1,014,435		989,334
Retained earnings	592,971		443,569
Accumulated other comprehensive income (loss)	6,327		(18,048		)
Total stockholders’ equity	1,613,733		1,414,855
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	3,619,760	$	3,251,957

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

SCHEDULE I — Condensed Financial Information of Registrant

ITC HOLDINGS CORP.

CONDENSED STATEMENTS OF OPERATIONS (PARENT COMPANY ONLY)

	Year Ended December 31,
(In thousands)	2013			2012			2011
Other income	$	1,487		$	2,165		$	2,556
General and administrative expense	(56,707		)	(31,833		)	(11,409		)
Interest expense	(98,660		)	(90,289		)	(88,618		)
Other expense	(3,609		)	(812		)	(517		)
LOSS BEFORE INCOME TAXES	(157,489		)	(120,769		)	(97,988		)
INCOME TAX BENEFIT	(72,798		)	(49,141		)	(47,545		)
LOSS AFTER TAXES	(84,691		)	(71,628		)	(50,443		)
EQUITY IN SUBSIDIARIES’ NET EARNINGS	318,197			259,504			222,128
NET INCOME	$	233,506		$	187,876		$	171,685

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

SCHEDULE I — Condensed Financial Information of Registrant

ITC HOLDINGS CORP.

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (PARENT COMPANY ONLY)

	Year Ended December 31,
(In thousands)	2013		2012			2011
NET INCOME	$	233,506	$	187,876		$	171,685
OTHER COMPREHENSIVE INCOME (LOSS)
Derivative instruments, net of tax	24,304		(2,680		)	(16,556		)
Available-for-sale securities, net of tax	71		—			—
TOTAL OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX	24,375		(2,680		)	(16,556		)
TOTAL COMPREHENSIVE INCOME	$	257,881	$	185,196		$	155,129

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

SCHEDULE I — Condensed Financial Information of Registrant

ITC HOLDINGS CORP.

CONDENSED STATEMENTS OF CASH FLOWS (PARENT COMPANY ONLY)

	Year Ended December 31,
(In thousands)	2013			2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	233,506		$	187,876		171,685
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in subsidiaries’ earnings	(318,197		)	(259,504		)	(222,128		)
Dividends from subsidiaries	169,973			127,412			304,244
Deferred income tax expense	(117,956		)	(87,861		)	(94,663		)
Intercompany tax payments from subsidiaries	112,008			83,144			86,226
Share-based compensation expense	15,667			15,622			15,392
Other	(226		)	2,438			3,423
Changes in assets and liabilities, exclusive of changes shown separately:
Accounts receivable from subsidiaries	(979		)	(9,677		)	(11,062		)
Prepaid and other current assets	16,948			(21,803		)	1,566
Accounts payable	(2,294		)	2,680			4,126
Accrued payroll	1,190			2,727			(593		)
Accrued interest	6,501			93			65
Tax benefit for excess tax deductions of share-based compensation	(4,302		)	(23,022		)	(28,114		)
Other current liabilities	2,099			20,954			26,144
Other non-current assets and liabilities, net	12,465			(65		)	1,008
Net cash provided by operating activities	126,403			41,014			257,319
CASH FLOWS FROM INVESTING ACTIVITIES
Equity contribution to subsidiaries	(339,770		)	(337,630		)	(472,964		)
Return of capital from subsidiaries	96,120			91,399			228,600
Proceeds from sale of marketable securities	20,844			5,935			3,839
Purchases of marketable securities	(22,250		)	(11,779		)	(8,136		)
Net cash used in investing activities	(245,056		)	(252,075		)	(248,661		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	548,484			—			—
Borrowings under revolving credit agreement	222,800			295,450			—
Borrowings under term loan credit agreement	390,000			200,000			—
Retirement of long-term debt	(267,000		)	—			—
Repayments of revolving credit agreement	(252,400		)	(265,850		)	—
Repayments of term loan credit agreements	(450,000		)	—			—
Issuance of common stock	10,042			14,189			18,993
Dividends on common stock	(84,129		)	(75,153		)	(70,363		)
Tax benefit for excess tax deductions of share-based compensation	4,302			23,022			28,114
Other	861			(7,291		)	(7,546		)
Net cash provided by (used in) financing activities	122,960			184,367			(30,802		)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	4,307			(26,694		)	(22,144		)
CASH AND CASH EQUIVALENTS — Beginning of period	22,546			49,240			71,384
CASH AND CASH EQUIVALENTS — End of period	$	26,853		$	22,546		$	49,240
Supplementary cash flows information:
Interest paid	$	90,224		$	88,303		$	86,649
Income taxes paid	20,092			41,174			34,127
Supplementary non-cash investing and financing activities:
Equity transfers to subsidiaries	6,213			6,470			12,892

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

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, 2013 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, 2013, the maturities of our debt outstanding were as follows:

(In thousands)
2014	$	50,000
2015	—
2016	395,000
2017	50,000
2018	385,000
2019 and thereafter	1,005,000
Total	$	1,885,000

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 $1,864.7 million and $1,707.2 million at December 31, 2013 and 2012, respectively. The total book value of the ITC Holdings Senior Notes, net of discount, was $1,741.9 million and $1,460.0 million at December 31, 2013 and 2012, respectively. At December 31, 2013, we had a total of $140.0 million outstanding under our term loan credit agreement, which is a variable rate loan. No amount was outstanding under our revolving credit agreement at December 31, 2013. At December 31, 2012, we had a total of $229.6 millionoutstanding under our revolving and term loan credit agreements. 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

Our debt instruments contain numerous financial and operating covenants that place significant restrictions on certain transactions, such as incurring additional indebtedness, engaging in sale and lease-back transactions, creating liens or other encumbrances, entering into mergers, consolidations, liquidations or dissolutions and paying dividends. In addition, the covenants require us to meet certain financial ratios, such as maintaining certain debt to capitalization ratios. At December 31, 2013, we were in compliance with all debt covenants.

3.     RELATED-PARTY TRANSACTIONS

ITCTransmission, MTH, ITC Midwest and other subsidiaries paid cash dividends to ITC Holdings totaling $170.0 million, $127.4 million and $304.2 million in 2013, 2012 and 2011, respectively. ITCTransmission, MTH, ITC Midwest and other subsidiaries recognized a return of capital to ITC Holdings totaling $96.1 million, $91.4 million and $228.6 million in 2013, 2012 and 2011, respectively.

Additionally, ITCTransmission paid $39.1 million, $18.9 million and $51.6 million to ITC Holdings under an intercompany tax sharing arrangement during 2013, 2012 and 2011, respectively. MTH paid $30.0 million, $17.6 million and $23.3 million to ITC Holdings under an intercompany tax sharing arrangement during 2013, 2012 and 2011, respectively. Additionally, ITC Midwest paid $33.6 million, $37.2 million and $11.3 million to ITC Holdings under an intercompany tax sharing arrangement during 2013, 2012 and 2011, respectively. ITC Great Plains paid $9.4 million and $4.3 million to ITC Holdings under an intercompany tax sharing arrangement during 2013 and 2012, respectively. No payments were made by ITC Great Plains in 2011.

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SUBSEQUENT EVENTS

12 Months Ended

Dec. 31, 2013

Subsequent Events [Abstract]

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS

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 will be distributed on February 28, 2014, to shareholders of record on February 18, 2014. The stock split will increase our outstanding common stock from approximately 52.5 million shares to approximately 157.5 million shares. Our historical outstanding shares and earnings per share will be recast upon the distribution.

The estimated pro forma impact of the stock split on our stockholders’ equity at December 31, 2013 is presented in the following table:

	Historical				Pro Forma
	December 31, 2013		Adjustment		December 31, 2013
(In thousands, except share data)	(Audited)		(Unaudited)		(Unaudited)
Common stock, without par value, 100,000,000 shares authorized, 52,500,265 shares issued and outstanding at December 31, 2013 (a)	$	1,014,435	$	—	$	1,014,435
Retained earnings	592,970		—		592,970
Accumulated other comprehensive income	6,327		—		6,327
Total stockholders’ equity	$	1,613,732	$	—	$	1,613,732

____________________________

(a) If the stock split had been paid at December 31, 2013, it would have increased the shares issued and outstanding on that date to 157,500,795. Authorized shares increased in January 2014 upon filing an amendment to the Articles of Incorporation with the State of Michigan.

The following table provides the estimated pro forma effects on our earnings per share, as calculated in Note 9, for the year ended December 31, 2013:

	Historical					Pro Forma
	December 31, 2013		Adjustment			December 31, 2013
(In thousands, except per share and share data)	(Audited)		(Unaudited)			(Unaudited)
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
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

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GOODWILL AND INTANGIBLE ASSETS (Details) (USD $)	12 Months Ended							0 Months Ended			0 Months Ended					12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013 ITCTransmission	Dec. 31, 2012 ITCTransmission	Dec. 31, 2013 METC LLC	Dec. 31, 2012 METC LLC	Jan. 01, 2007 METC LLC Regulatory Deferrals	Dec. 31, 2013 METC LLC Regulatory Deferrals	Dec. 31, 2012 METC LLC Regulatory Deferrals	Jan. 01, 2007 METC LLC ADIT Deferral	Dec. 31, 2013 METC LLC ADIT Deferral	Dec. 31, 2012 METC LLC ADIT Deferral	Dec. 31, 2013 ITC Midwest LLC	Dec. 31, 2012 ITC Midwest LLC	Dec. 31, 2013 ITC Great Plains LLC	Dec. 31, 2012 ITC Great Plains LLC
Goodwill and Intangible Assets
Goodwill	$ 950,163,000	$ 950,163,000	$ 950,163,000	$ 173,400,000	$ 173,400,000	$ 453,800,000	$ 453,800,000							$ 323,000,000	$ 323,000,000
Intangible assets	49,328,000	48,492,000							25,700,000	27,700,000						12,100,000	8,200,000
Intangible assets, useful Life								20 years			18 years					50 years
Accumulated amortization	21,616,000	18,397,000										11,500,000	12,600,000			400,000	300,000
Amortization expense	$ 3,200,000	$ 3,100,000	$ 3,100,000

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COMMITMENTS AND CONTINGENT LIABILITIES (Tables)

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies Disclosure [Abstract]

Schedule of Future Minimum Lease Payments for Operating Leases

Future minimum lease payments under the leases at December 31, 2013 were:

(In thousands)
2014	$	604
2015	237
2016	178
2017	180
2018 and thereafter	95
Total minimum lease payments	$	1,294

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SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

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 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.

Excess Tax Benefits From Share-based Compensation

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 Receivables

We recognize losses for uncollectible accounts based on specific identification of any such items. As of December 31, 2013 and 2012, 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 $109.4 million, $97.3 million and $85.8 million for 2013, 2012 and 2011, 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 2.2%, 2.4% and 2.4% for 2013, 2012 and 2011, 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 and removal costs incurred are deducted from regulatory liabilities. 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 $8.0 million, $7.0 million and $4.7 million for 2013, 2012 and 2011, 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.

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.

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. 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 by performing a qualitative analysis for each of our MISO Regulated Operating Subsidiaries as of October 1, 2013 and determined that no impairment exists. There were no events subsequent to October 1, 2013 that indicated impairment of our goodwill. 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 and the amortization of our debt discounts for 2013, 2012 and 2011 of $4.1 million, $4.0 million and $3.8 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 obligation 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 2013. Our asset retirement obligations as of December 31, 2013 and 2012 of $5.7 million and $5.1 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.

General Interconnection Projects

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 have been 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 investment in transmission facilities are recorded to property, plant and equipment, and are recorded net of any contribution in aid of construction received from the generator pursuant to the provisions of the MISO or SPP tariff. 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.

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 our stock options, which have graded vesting schedules, on a straight-line basis over the requisite service period and not for each separately vesting portion of the award. 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.

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 2009 and earlier. State and city jurisdictions that remain subject to examination range from tax years 2009 to 2012. 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.

Operating Leases

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.

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SIGNIFICANT ACCOUNTING POLICIES (Tables)

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Supplementary Cash Flows Information

The following table presents certain supplementary cash flows information for the years ended December 31, 2013, 2012 and 2011:

	Year Ended December 31,
(In thousands)	2013		2012		2011
Supplementary cash flows information:
Interest paid (net of interest capitalized)	$	155,112	$	148,598	$	142,101
Income taxes paid — net	20,092		41,174		34,127
Supplementary non-cash investing and financing activities:
Additions to property, plant and equipment and other long-lived assets (a)	$	68,276	$	94,218	$	102,091
Allowance for equity funds used during construction	30,159		23,000		16,699

____________________________

(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, 2013, 2012 or 2011, respectively, but have been or will be included as a cash outflow from investing activities for expenditures for property, plant and equipment when paid.

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CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
CASH FLOWS FROM OPERATING ACTIVITIES
NET INCOME	$ 233,506	[1],[2]	$ 187,876	[1]	$ 171,685
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	118,596		106,512		94,981
Recognition of and refund and collection of revenue accruals and deferrals — including accrued interest	(11,972)		(13,052)		56,944
Deferred income tax expense	76,703		67,285		30,797
Allowance for equity funds used during construction	(30,159)		(23,000)		(16,699)
Other	17,864		13,772		13,361
Changes in assets and liabilities, exclusive of changes shown separately:
Accounts receivable	(16,312)		1,721		2,434
Inventory	5,371		(2,502)		7,431
Prepaid and other current assets	16,891		(25,102)		1,134
Accounts payable	17,638		(5,400)		12,573
Accrued payroll	1,619		1,583		(1,096)
Accrued interest	8,341		1,066		917
Accrued taxes	6,113		24,247		34,279
Tax benefit on the excess tax deduction of common stock	(4,302)		(23,022)		(28,114)
Other current liabilities	1,630		2,912		(246)
Other non-current assets and liabilities, net	7,669		12,627		535
Net cash provided by operating activities	449,196		327,523		380,916
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(821,588)		(802,763)		(556,931)
Proceeds from sale of marketable securities	20,844		5,935		3,839
Purchases of marketable securities	(22,250)		(11,779)		(8,136)
Other	(3,294)		(454)		1,033
Net cash used in investing activities	(826,288)		(809,061)		(560,195)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	933,025		175,000		0
Borrowings under revolving credit agreements	1,090,100		1,355,150		1,065,215
Borrowings under term loan credit agreements	675,000		200,000		0
Retirement of long-term debt	(452,000)		0		0
Repayments of revolving credit agreements	(1,146,700)		(1,228,410)		(917,555)
Repayments of term loan credit agreements	(635,000)		0		0
Issuance of common stock	10,042		14,189		18,993
Dividends on common stock	(84,129)		(75,153)		(70,363)
Refundable deposits from generators for transmission network upgrades	32,281		33,310		35,768
Repayment of refundable deposits from generators for transmission network upgrades	(38,236)		(38,253)		(6,976)
Tax benefit on the excess tax deduction of common stock	4,302		23,022		28,114
Other	(3,505)		(9,474)		(10,682)
Net cash provided by financing activities	385,180		449,381		142,514
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	8,088		(32,157)		(36,765)
CASH AND CASH EQUIVALENTS — Beginning of period	26,187		58,344		95,109
CASH AND CASH EQUIVALENTS — End of period	$ 34,275		$ 26,187		$ 58,344

[1] During the years ended December 31, 2013 and 2012, we expensed external legal, advisory and financial services fees of $43.1 million and $19.4 million, respectively, and internal labor and related costs of approximately $7.8 million and $7.1 million, respectively, related to the Entergy Transaction. 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.

[2] 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 for the external costs related to the Entergy transaction incurred in 2013, 2012 and 2011 that originally were recorded as non-deductible for income tax provision purposes.

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REGULATORY MATTERS (Tables)

12 Months Ended

Dec. 31, 2013

Regulated Operations [Abstract]

Changes in Regulatory Assets and Liabilities

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, 2013:

(In thousands)	Total
Balance as of December 31, 2012	$	(72,168	)
Net refund of 2011 revenue deferrals and accruals, including accrued interest	47,061
Net revenue deferral for the year ended December 31, 2013	(32,782		)
Net accrued interest payable for the year ended December 31, 2013	(2,307		)
Balance as of December 31, 2013	$	(60,196	)

Schedule of Regulatory Assets and Liabilities

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

(In thousands)	Total
Current assets	$	6,334
Non-current assets — other	3,037
Current liabilities	(33,120		)
Non-current liabilities	(36,447		)
Balance as of December 31, 2013	$	(60,196	)

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SHARE-BASED COMPENSATION Rollforwards (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Stock Options
Options Roll Forward
Exercisable	1,128,540	1,030,594
Exercisable, weighted average exercise price	$ 42.98	$ 38.10
Beginning balance	1,603,429
Beginning, weighted average exercise price	$ 49.02
Granted	310,111
Granted, weighted average exercise price	$ 87.93
Excercised	(166,338)
Excercised, weighted average exercise price	$ 49.09
Forfeited	(23,926)
Forfeited, weighted average exercise price	$ 79.03
Ending balance	1,723,276
Ending, weighted average exercise price	$ 55.60
Restricted Stock
Restricted Stock and Deferred Stock Rollforwards
Beginning balance	523,350
Beginning, weighted average grant date fair value	$ 62.63
Granted	128,192
Granted - Weighted average grant date fair value	$ 88.27	$ 71.65	$ 71.27
Vested	(175,182)
Vested, weighted average grant date fair value	$ 52.99
Forfeited	(14,038)
Forfeited, weighted average grant date fair value	$ 76.13
Ending balance	462,322	523,350
Ending, weighted average grant date fair value	$ 72.97	$ 62.63

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FAIR VALUE MEASUREMENTS (Tables)

12 Months Ended

Dec. 31, 2013

Fair Value Disclosures [Abstract]

Assets and Liabilities at Fair Value Subject to Three-Tier Hierarchy

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	$	—	$	—

Our assets and liabilities measured at fair value subject to the three-tier hierarchy at December 31, 2012, 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	$	13,127	$	10,037		$	—
Mutual funds — fixed income securities	21,332		—			—
Mutual funds — equity securities	1,612		—			—
Interest rate swap derivatives	—		2,725			—
Financial liabilities measured on a recurring basis:
Interest rate swap derivatives	—		(31,507		)	—
Total	$	36,071	$	(18,745	)	$	—

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REGULATORY ASSETS AND LIABILITIES Regulatory Assets (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013 Revenue Accruals, Accrued Interest	Dec. 31, 2012 Revenue Accruals, Accrued Interest	Dec. 31, 2013 Income Taxes Recoverable Related to AFUDC Equity	Dec. 31, 2012 Income Taxes Recoverable Related to AFUDC Equity	Dec. 31, 2013 Pensions and Postretirement	Dec. 31, 2012 Pensions and Postretirement	Dec. 31, 2013 Income Taxes Recoverable Related to Implementation of the Michigan Corporate Income Tax	Dec. 31, 2012 Income Taxes Recoverable Related to Implementation of the Michigan Corporate Income Tax	Dec. 31, 2013 Other	Dec. 31, 2012 Other	Dec. 31, 2013 ITCTransmission ADIT Deferral	Dec. 31, 2012 ITCTransmission ADIT Deferral	Feb. 28, 2003 ITCTransmission ADIT Deferral	Dec. 31, 2013 METC LLC Regulatory Deferrals	Dec. 31, 2012 METC LLC Regulatory Deferrals	Jan. 31, 2007 METC LLC Regulatory Deferrals	Dec. 31, 2013 METC LLC ADIT Deferral	Dec. 31, 2012 METC LLC ADIT Deferral	Jan. 31, 2007 METC LLC ADIT Deferral	Dec. 31, 2013 ITC Great Plains LLC Start-up, Development and Pre-construction	Dec. 31, 2012 ITC Great Plains LLC Start-up, Development and Pre-construction
Regulatory Assets
Regulatory assets — revenue accruals, including accrued interest	$ 6,334	$ 7,489
Current regulatory asset			114	131
Regulatory assets — revenue accruals, including accrued interest	3,037	2,719
Regulatory asset	188,439	190,586	27	17	75,798	57,135	15,079	28,847	8,869	8,869	1,656	1,500	27,776	30,806	60,600	10,029	10,800	15,400	25,945	28,304	42,500	13,916	14,117
Accumulated amortization													$ 32,826	$ 29,796		$ 5,400	$ 4,628		$ 16,511	$ 14,152

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RETIREMENT BENEFITS AND ASSETS HELD IN TRUST Defined Benefit Plans Disclosures (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Change in Plans' Assets:
Accumulated benefit obligation	$ (61,832)	$ (55,649)
Accumulated benefit obligation
Accumulated benefit obligation	(61,832)	(55,649)
Defined Benefit Plans
Change in Benefit Obligation:
Beginning obligation	(72,400)	(56,069)
Service cost	(5,261)	(4,160)	(3,585)
Interest cost	(2,792)	(2,590)	(2,458)
Actuarial net gain (loss)	6,161	(10,481)
Ending obligation	(73,468)	(72,400)	(56,069)
Change in Plans' Assets:
Beginning plan assets at fair value	38,130	28,276
Actual return on plan assets	4,650	3,331
Employer contributions	6,938	7,023
Ending plan assets at fair value	48,894	38,130	28,276
Funded status, underfunded	(24,574)	(34,270)
Accumulated benefit obligation	(61,832)	(55,649)
Funded Status:
Accrued liabilities	(35,003)	(35,899)
Pension assets — other assets — other	10,429	1,629
Total	(24,574)	(34,270)
Accumulated benefit obligation
Accumulated benefit obligation	(61,832)	(55,649)
Unrecognized Amounts in Other Regulatory Assets:
Net actuarial loss	12,787	23,444
Prior service credit	(17)	(59)
Total	12,770	23,385
Retirement Plan
Change in Plans' Assets:
Employer contributions	6,900	7,000	3,600
Accumulated benefit obligation	(36,033)	(33,051)
Accumulated benefit obligation
Accumulated benefit obligation	(36,033)	(33,051)
Supplemental Benefit Plans
Change in Plans' Assets:
Employer contributions	600	4,700	3,100
Accumulated benefit obligation	(25,799)	(22,598)
Funded Status:
Pension assets — other assets — other	21,100	22,400
Accumulated benefit obligation
Accumulated benefit obligation	(25,799)	(22,598)
Other Postretirement Benefits Plan
Change in Benefit Obligation:
Beginning obligation	(37,015)	(30,679)
Service cost	(5,774)	(5,433)	(3,431)
Interest cost	(1,562)	(1,552)	(1,285)
Actuarial net gain (loss)	1,491	474
Ending obligation	(42,706)	(37,015)	(30,679)
Change in Plans' Assets:
Beginning plan assets at fair value	19,670	13,549
Actual return on plan assets	2,857	1,747
Employer contributions	1,477	4,374	3,400
Employer provided retiree premiums	154	175
Ending plan assets at fair value	24,004	19,670	13,549
Funded status, underfunded	(18,702)	17,345
Funded Status:
Accrued liabilities	(18,702)	(17,345)
Total	(18,702)	(17,345)
Unrecognized Amounts in Other Regulatory Assets:
Net actuarial loss	2,309	5,461
Prior service credit	0	0
Total	2,309	5,461
Change in Benefit Obligation | Defined Benefit Plans
Change in Benefit Obligation:
Benefits paid	824	900
Change in Plans' Assets:
Benefits paid	824	900
Change in Benefit Obligation | Other Postretirement Benefits Plan
Change in Benefit Obligation:
Benefits paid	154	175
Change in Plans' Assets:
Benefits paid	154	175
Change in Plan Assets | Defined Benefit Plans
Change in Benefit Obligation:
Benefits paid	(824)	(500)
Change in Plans' Assets:
Benefits paid	(824)	(500)
Change in Plan Assets | Other Postretirement Benefits Plan
Change in Benefit Obligation:
Benefits paid	154	175
Change in Plans' Assets:
Benefits paid	$ 154	$ 175

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CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Current assets
Cash and cash equivalents	$ 34,275		$ 26,187
Accounts receivable	89,348		72,192
Inventory	31,986		37,357
Deferred income taxes	17,225		23,014
Regulatory assets — revenue accruals, including accrued interest	6,334		7,489
Prepaid and other current assets	12,370		31,987
Total current assets	191,538		198,226
Property, plant and equipment (net of accumulated depreciation and amortization of $1,330,094 and $1,269,810, respectively)	4,846,526		4,134,579
Other assets
Goodwill	950,163		950,163
Intangible assets (net of accumulated amortization of $21,616 and $18,397, respectively)	49,328		48,492
Other regulatory assets	179,068		180,378
Deferred financing fees (net of accumulated amortization of $15,261 and $17,838, respectively)	25,585		19,293
Other	40,035		33,678
Total other assets	1,244,179		1,232,004
TOTAL ASSETS	6,282,243	[1]	5,564,809	[1]
Current liabilities
Accounts payable	111,145		123,022
Accrued payroll	21,930		20,740
Accrued interest	53,049		44,708
Accrued taxes	29,805		28,117
Regulatory liabilities — revenue deferrals, including accrued interest	33,120	[2]	53,763	[2]
Refundable deposits from generators for transmission network upgrades	23,283		40,745
Debt maturing within one year	200,000		651,929
Other	27,047		40,287
Total current liabilities	499,379		1,003,311
Accrued pension and postretirement liabilities	53,704		53,243
Deferred income taxes	562,938		460,072
Regulatory liabilities — revenue deferrals, including accrued interest	36,447	[2]	28,613	[2]
Regulatory liabilities — accrued asset removal costs	67,571		75,477
Refundable deposits from generators for transmission network upgrades	19,328		7,623
Other	17,032		26,317
Long-term debt	3,412,112		2,495,298
Commitments and contingent liabilities (Notes 4 and 16)
STOCKHOLDERS’ EQUITY
Common stock, without par value, 100,000,000 shares authorized, 52,500,265 and 52,248,514 shares issued and outstanding at December 31, 2013 and 2012, respectively	1,014,435		989,334
Retained earnings	592,970		443,569
Accumulated other comprehensive income (loss)	6,327		(18,048)
Total stockholders’ equity	1,613,732		1,414,855
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$ 6,282,243		$ 5,564,809

[1] 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.

[2] 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.

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SEGMENT INFORMATION (Tables)

12 Months Ended

Dec. 31, 2013

Segment Reporting [Abstract]

Financial Information by Reportable Segment

	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 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

	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 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

	Regulated
	Operating		ITC Holdings			Reconciliations/
2011	Subsidiaries		and Other			Eliminations			Total
(In thousands)
Operating revenues	$	757,465	$	486		$	(554	)	$	757,397
Depreciation and amortization	94,520		461			—			94,981
Interest expense — net	58,795		88,609			(468		)	146,936
Income before income taxes	367,628		(101,194		)	—			266,434
Income tax provision (benefit)	143,416		(48,667		)	—			94,749
Net income	224,211		171,685			(224,211		)	171,685
Property, plant and equipment — net	3,404,091		11,732			—			3,415,823
Goodwill	950,163		—			—			950,163
Total assets (a)	4,711,274		2,845,182			(2,733,090		)	4,823,366
Capital expenditures	554,692		7,633			(5,394		)	556,931

____________________________

(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.

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SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT Condensed Statements of Cash Flows (Parent Company) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
CASH FLOWS FROM OPERATING ACTIVITIES
NET INCOME	$ 233,506	[1],[2]	$ 187,876	[1]	$ 171,685
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred income tax expense	76,703		67,285		30,797
Share-based compensation expense	15,666		15,622		15,391
Other	17,864		13,772		13,361
Changes in assets and liabilities, exclusive of changes shown separately:
Prepaid and other current assets	16,891		(25,102)		1,134
Accounts payable	17,638		(5,400)		12,573
Accrued payroll	1,619		1,583		(1,096)
Accrued interest	8,341		1,066		917
Tax benefit for excess tax deductions of share-based compensation	(4,302)		(23,022)		(28,114)
Other current liabilities	1,630		2,912		(246)
Other non-current assets and liabilities, net	7,669		12,627		535
Net cash provided by operating activities	449,196		327,523		380,916
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from sale of marketable securities	20,844		5,935		3,839
Purchases of marketable securities	(22,250)		(11,779)		(8,136)
Net cash used in investing activities	(826,288)		(809,061)		(560,195)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	933,025		175,000		0
Borrowings under revolving credit agreement	1,090,100		1,355,150		1,065,215
Borrowings under term loan credit agreements	675,000		200,000		0
Retirement of long-term debt	(452,000)		0		0
Repayments of revolving credit agreement	(1,146,700)		(1,228,410)		(917,555)
Repayments of term loan credit agreements	(635,000)		0		0
Issuance of common stock	10,042		14,189		18,993
Dividends on common stock	(84,129)		(75,153)		(70,363)
Tax benefit for excess tax deductions of share-based compensation	4,302		23,022		28,114
Other	(3,505)		(9,474)		(10,682)
Net cash provided by (used in) financing activities	385,180		449,381		142,514
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	8,088		(32,157)		(36,765)
CASH AND CASH EQUIVALENTS — Beginning of period	26,187		58,344		95,109
CASH AND CASH EQUIVALENTS — End of period	34,275		26,187		58,344
Supplementary cash flows information:
Interest paid (net of interest capitalized)	155,112		148,598		142,101
Income taxes paid — net	20,092		41,174		34,127
ITC Holdings Corp.
CASH FLOWS FROM OPERATING ACTIVITIES
NET INCOME	233,506		187,876		171,685
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in subsidiaries’ earnings	(318,197)		(259,504)		(222,128)
Dividends from subsidiaries	169,973		127,412		304,244
Deferred income tax expense	(117,956)		(87,861)		(94,663)
Intercompany tax payments from subsidiaries	112,008		83,144		86,226
Share-based compensation expense	15,667		15,622		15,392
Other	(226)		2,438		3,423
Changes in assets and liabilities, exclusive of changes shown separately:
Accounts receivable from subsidiaries	(979)		(9,677)		(11,062)
Prepaid and other current assets	16,948		(21,803)		1,566
Accounts payable	(2,294)		2,680		4,126
Accrued payroll	1,190		2,727		(593)
Accrued interest	6,501		93		65
Tax benefit for excess tax deductions of share-based compensation	(4,302)		(23,022)		(28,114)
Other current liabilities	2,099		20,954		26,144
Other non-current assets and liabilities, net	12,465		(65)		1,008
Net cash provided by operating activities	126,403		41,014		257,319
CASH FLOWS FROM INVESTING ACTIVITIES
Equity contribution to subsidiaries	(339,770)		(337,630)		(472,964)
Return of capital from subsidiaries	96,120		91,399		228,600
Proceeds from sale of marketable securities	20,844		5,935		3,839
Purchases of marketable securities	(22,250)		(11,779)		(8,136)
Net cash used in investing activities	(245,056)		(252,075)		(248,661)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	548,484		0		0
Borrowings under revolving credit agreement	222,800		295,450		0
Borrowings under term loan credit agreements	390,000		200,000		0
Retirement of long-term debt	(267,000)		0		0
Repayments of revolving credit agreement	(252,400)		(265,850)		0
Repayments of term loan credit agreements	(450,000)		0		0
Issuance of common stock	10,042		14,189		18,993
Dividends on common stock	(84,129)		(75,153)		(70,363)
Tax benefit for excess tax deductions of share-based compensation	4,302		23,022		28,114
Other	861		(7,291)		(7,546)
Net cash provided by (used in) financing activities	122,960		184,367		(30,802)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	4,307		(26,694)		(22,144)
CASH AND CASH EQUIVALENTS — Beginning of period	22,546		49,240		71,384
CASH AND CASH EQUIVALENTS — End of period	26,853		22,546		49,240
Supplementary cash flows information:
Interest paid (net of interest capitalized)	90,224		88,303		86,649
Income taxes paid — net	20,092		41,174		34,127
Supplementary non-cash investing and financing activities:
Equity transfers to subsidiaries	$ 6,213		$ 6,470		$ 12,892

[1] During the years ended December 31, 2013 and 2012, we expensed external legal, advisory and financial services fees of $43.1 million and $19.4 million, respectively, and internal labor and related costs of approximately $7.8 million and $7.1 million, respectively, related to the Entergy Transaction. 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.

[2] 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 for the external costs related to the Entergy transaction incurred in 2013, 2012 and 2011 that originally were recorded as non-deductible for income tax provision purposes.

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CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (USD $) In Thousands, except Share data	Total		Common Stock	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Total Stockholders' Equity
Stockholders' equity at Dec. 31, 2010			$ 886,808	$ 229,437	$ 1,188	$ 1,117,433
Common stock, shares at Dec. 31, 2010			50,715,805
NET INCOME	171,685			171,685		171,685
Repurchase and retirement of common stock			(6,401)			(6,401)
Repurchase and retirement of common stock, shares			(89,715)
Dividends declared on common stock				(70,363)		(70,363)
Stock option exercises			17,666			17,666
Stock option exercises, shares			543,775
Shares issued under the Employee Stock Purchase Plan			1,327			1,327
Shares issued under the Employee Stock Purchase Plan, shares			23,027
Issuance of restricted stock			142,999
Forfeiture of restricted stock				57		57
Forfeiture of restricted stock, shares			(18,012)
Vesting of deferred stock units			5,489
Share-based compensation, net of forfeitures			15,334			15,334
Tax benefit for excess tax deductions of share-based compensation			28,114			28,114
Other comprehensive income (loss), net of tax (Note 13)	(16,556)				(16,556)	(16,556)
Other			596			596
Stockholders' equity at Dec. 31, 2011			943,444	330,816	(15,368)	1,258,892
Common stock, shares at Dec. 31, 2011			51,323,368
NET INCOME	187,876	[1]		187,876		187,876
Repurchase and retirement of common stock			(7,266)			(7,266)
Repurchase and retirement of common stock, shares			(99,533)
Dividends declared on common stock				(75,153)		(75,153)
Stock option exercises			12,593			12,593
Stock option exercises, shares			851,720
Shares issued under the Employee Stock Purchase Plan			1,596			1,596
Shares issued under the Employee Stock Purchase Plan, shares			25,521
Issuance of restricted stock			158,599
Forfeiture of restricted stock				30		30
Forfeiture of restricted stock, shares			(11,161)
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 income (loss), net of tax (Note 13)	(2,680)				(2,680)	(2,680)
Other			353			353
Stockholders' equity at Dec. 31, 2012	1,414,855		989,334	443,569	(18,048)	1,414,855
Common stock, shares at Dec. 31, 2012	52,248,514		52,248,514
NET INCOME	233,506	[1],[2]		233,506		233,506
Repurchase and retirement of common stock			(4,885)			(4,885)
Repurchase and retirement of common stock, shares			(54,440)
Dividends declared on common stock				(84,129)		(84,129)
Stock option exercises			8,165			8,165
Stock option exercises, shares			166,338
Shares issued under the Employee Stock Purchase Plan			1,877			1,877
Shares issued under the Employee Stock Purchase Plan, shares			25,699
Issuance of restricted stock			128,192
Forfeiture of restricted stock				24		24
Forfeiture of restricted stock, shares			(14,038)
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 (loss), net of tax (Note 13)	24,375				24,375	24,375
Stockholders' equity at Dec. 31, 2013	$ 1,613,732		$ 1,014,435	$ 592,970	$ 6,327	$ 1,613,732
Common stock, shares at Dec. 31, 2013	52,500,265		52,500,265

[1] During the years ended December 31, 2013 and 2012, we expensed external legal, advisory and financial services fees of $43.1 million and $19.4 million, respectively, and internal labor and related costs of approximately $7.8 million and $7.1 million, respectively, related to the Entergy Transaction. 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.

[2] 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 for the external costs related to the Entergy transaction incurred in 2013, 2012 and 2011 that originally were recorded as non-deductible for income tax provision purposes.

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SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT Condensed Statements of Operations (Parent Company Only) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended																12 Months Ended
	Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013		Dec. 31, 2012		Sep. 30, 2012		Jun. 30, 2012		Mar. 31, 2012		Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Condensed Financial Statements, Captions
Other income																	$ 1,139		$ 769		$ 844
General and administrative expense																	(149,109)		(112,091)		(82,790)
Interest expense																	(168,319)		(155,734)		(146,936)
Other expense																	(6,571)		(4,218)		(3,962)
INCOME BEFORE INCOME TAXES																	352,368		296,508		266,434
INCOME TAX PROVISION																	118,862		108,632		94,749
NET INCOME	76,937	[1],[2]	58,984	[1],[2]	47,395	[1],[2]	50,190	[1],[2]	48,256	[1]	51,183	[1]	42,386	[1]	46,051	[1]	233,506	[1],[2]	187,876	[1]	171,685
ITC Holdings Corp.
Condensed Financial Statements, Captions
Other income																	1,487		2,165		2,556
General and administrative expense																	(56,707)		(31,833)		(11,409)
Interest expense																	(98,660)		(90,289)		(88,618)
Other expense																	(3,609)		(812)		(517)
INCOME BEFORE INCOME TAXES																	(157,489)		(120,769)		(97,988)
INCOME TAX PROVISION																	(72,798)		(49,141)		(47,545)
LOSS AFTER TAXES																	(84,691)		(71,628)		(50,443)
EQUITY IN SUBSIDIARIES’ NET EARNINGS																	318,197		259,504		222,128
NET INCOME																	$ 233,506		$ 187,876		$ 171,685

[1] During the years ended December 31, 2013 and 2012, we expensed external legal, advisory and financial services fees of $43.1 million and $19.4 million, respectively, and internal labor and related costs of approximately $7.8 million and $7.1 million, respectively, related to the Entergy Transaction. 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.

[2] 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 for the external costs related to the Entergy transaction incurred in 2013, 2012 and 2011 that originally were recorded as non-deductible for income tax provision purposes.

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DEBT Schedule of Debt (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013 ITC Holdings Corp.	Dec. 31, 2012 ITC Holdings Corp.	Dec. 31, 2013 ITC Holdings Corp. Revolving Credit Agreement	Dec. 31, 2012 ITC Holdings Corp. Revolving Credit Agreement	Dec. 31, 2012 ITC Holdings Corp. Senior Notes due July 15, 2013 Unsecured Debt		Dec. 31, 2013 ITC Holdings Corp. Senior Notes, Series A, due September 20, 2014 Unsecured Debt		Dec. 31, 2012 ITC Holdings Corp. Senior Notes, Series A, due September 20, 2014 Unsecured Debt	Dec. 31, 2013 ITC Holdings Corp. Senior Notes due September 30, 2016 Unsecured Debt	Dec. 31, 2012 ITC Holdings Corp. Senior Notes due September 30, 2016 Unsecured Debt	Dec. 31, 2013 ITC Holdings Corp. Senior Notes, Series B, due September 20, 2017 Unsecured Debt	Dec. 31, 2012 ITC Holdings Corp. Senior Notes, Series B, due September 20, 2017 Unsecured Debt	Dec. 31, 2013 ITC Holdings Corp. Senior Notes due September 30, 2036 Unsecured Debt	Dec. 31, 2012 ITC Holdings Corp. Senior Notes due September 30, 2036 Unsecured Debt	Dec. 31, 2013 ITC Holdings Corp. Senior Notes due January 31, 2018 Unsecured Debt	Dec. 31, 2012 ITC Holdings Corp. Senior Notes due January 31, 2018 Unsecured Debt	Dec. 31, 2013 ITC Holdings Corp. Senior Notes due January 15, 2020 Unsecured Debt	Dec. 31, 2012 ITC Holdings Corp. Senior Notes due January 15, 2020 Unsecured Debt	Dec. 31, 2013 ITC Holdings Corp. Senior Notes, Due July 1, 2023 Unsecured Debt	Jul. 03, 2013 ITC Holdings Corp. Senior Notes, Due July 1, 2023 Unsecured Debt	Dec. 31, 2013 ITC Holdings Corp. Senior Notes, Due July 1, 2043 Unsecured Debt	Jul. 03, 2013 ITC Holdings Corp. Senior Notes, Due July 1, 2043 Unsecured Debt	Dec. 31, 2013 ITC Holdings Corp. Term Loan Credit Agreement, due August 23, 2013 Unsecured Debt	Dec. 31, 2012 ITC Holdings Corp. Term Loan Credit Agreement, due August 23, 2013 Unsecured Debt		Aug. 23, 2012 ITC Holdings Corp. Term Loan Credit Agreement, due August 23, 2013 Unsecured Debt	Dec. 31, 2013 ITC Holdings Corp. Term Loan Credit Agreement, due September 30, 2016 Unsecured Debt	Dec. 31, 2013 ITCTransmission Revolving Credit Agreement	Dec. 31, 2012 ITCTransmission Revolving Credit Agreement	Dec. 31, 2012 ITCTransmission First Mortgage Bonds, Series A, due July 15, 2013 Secured Debt		Dec. 31, 2013 ITCTransmission First Mortgage Bonds, Series C, due March 31, 2036 Secured Debt	Dec. 31, 2012 ITCTransmission First Mortgage Bonds, Series C, due March 31, 2036 Secured Debt	Dec. 31, 2013 ITCTransmission First Mortgage Bonds, Series D, due April 1, 2018 Secured Debt	Dec. 31, 2012 ITCTransmission First Mortgage Bonds, Series D, due April 1, 2018 Secured Debt	Dec. 31, 2013 ITCTransmission First Mortgage Bonds, Series E, due August 15, 2043 Secured Debt	Dec. 31, 2013 METC LLC Revolving Credit Agreement	Dec. 31, 2012 METC LLC Revolving Credit Agreement	Dec. 31, 2013 METC LLC Senior Secured Notes due December 10, 2015 Secured Debt	Dec. 31, 2012 METC LLC Senior Secured Notes due December 10, 2015 Secured Debt	Dec. 31, 2013 METC LLC Senior Secured Notes due December 18, 2014 Secured Debt	Dec. 31, 2012 METC LLC Senior Secured Notes due December 18, 2014 Secured Debt	Dec. 31, 2013 METC LLC Senior Secured Notes due May 6, 2040 Secured Debt	Dec. 31, 2012 METC LLC Senior Secured Notes due May 6, 2040 Secured Debt	Dec. 31, 2013 METC LLC Senior Secured Notes, due October 26, 2042 Secured Debt	Dec. 31, 2012 METC LLC Senior Secured Notes, due October 26, 2042 Secured Debt	Oct. 26, 2012 METC LLC Senior Secured Notes, due October 26, 2042 Secured Debt	Dec. 31, 2013 ITC Midwest LLC Revolving Credit Agreement	Dec. 31, 2012 ITC Midwest LLC Revolving Credit Agreement	Dec. 31, 2013 ITC Midwest LLC First Mortgage Bonds, Series A, due January 31, 2038 Secured Debt	Dec. 31, 2012 ITC Midwest LLC First Mortgage Bonds, Series A, due January 31, 2038 Secured Debt	Dec. 31, 2013 ITC Midwest LLC First Mortgage Bonds, Series B, due December 22, 2017 Secured Debt	Dec. 31, 2012 ITC Midwest LLC First Mortgage Bonds, Series B, due December 22, 2017 Secured Debt	Dec. 31, 2013 ITC Midwest LLC First Mortgage Bonds, Series C, due December 22, 2020 Secured Debt	Dec. 31, 2012 ITC Midwest LLC First Mortgage Bonds, Series C, due December 22, 2020 Secured Debt	Dec. 31, 2013 ITC Midwest LLC First Mortgage Bonds, Series D, due December 17, 2024 Secured Debt	Dec. 31, 2012 ITC Midwest LLC First Mortgage Bonds, Series D, due December 17, 2024 Secured Debt	Dec. 31, 2013 ITC Midwest LLC First Mortgage Bonds, Series E, due January 19, 2027 Secured Debt	Dec. 31, 2012 ITC Midwest LLC First Mortgage Bonds, Series E, due January 19, 2027 Secured Debt	Jan. 19, 2012 ITC Midwest LLC First Mortgage Bonds, Series E, due January 19, 2027 Secured Debt	Dec. 31, 2013 ITC Midwest LLC First Mortgage Bonds, Series F, due April 30, 2043 Secured Debt	Apr. 04, 2013 ITC Midwest LLC First Mortgage Bonds, Series F, due April 30, 2043 Secured Debt	Dec. 31, 2013 ITC Great Plains LLC Revolving Credit Agreement	Dec. 31, 2012 ITC Great Plains LLC Revolving Credit Agreement	Dec. 31, 2013 ITC Great Plains LLC Term Loan Credit Agreement, due November 28, 2014 Unsecured Debt
Debt Instrument
Long-term debt	$ 3,100,900,000	$ 2,619,400,000	$ 1,741,900,000	$ 1,460,000,000	$ 0	$ 29,600,000	$ 266,935,000	[1]	$ 50,000,000	[1]	$ 50,000,000	$ 254,991,000	$ 254,988,000	$ 50,000,000	$ 50,000,000	$ 254,826,000	$ 254,818,000	$ 384,356,000	$ 384,198,000	$ 199,213,000	$ 199,080,000	$ 249,323,000		$ 299,209,000							$ 41,100,000	$ 78,700,000	$ 184,994,000	[1]	$ 99,918,000	$ 99,915,000	$ 99,951,000	$ 99,940,000	$ 284,548,000	$ 67,200,000	$ 10,500,000	$ 175,000,000	$ 175,000,000	$ 50,000,000	$ 50,000,000	$ 50,000,000	$ 50,000,000	$ 75,000,000	$ 75,000,000		$ 111,000,000	$ 115,300,000	$ 174,577,000	$ 174,559,000	$ 40,000,000	$ 40,000,000	$ 35,000,000	$ 35,000,000	$ 75,000,000	$ 75,000,000	$ 100,000,000	$ 100,000,000		$ 100,000,000		$ 51,900,000	$ 93,700,000
Interest rate							5.25%		6.04%		6.04%	5.875%	5.875%	6.23%	6.23%	6.375%	6.375%	6.05%	6.05%	5.50%	5.50%	4.05%	4.05%	5.30%	5.30%								4.45%		6.125%	6.125%	5.75%	5.75%	4.625%			5.75%	5.75%	6.63%	6.63%	5.64%	5.64%	3.98%	3.98%	3.98%			6.15%	6.15%	7.12%	7.12%	7.27%	7.27%	4.60%	4.60%	3.50%	3.50%	3.50%	4.09%	4.09%
Unamortized discount			3,082,000	1,916,000			65,000					9,000	12,000			174,000	182,000	644,000	802,000	787,000	920,000	677,000		791,000									6,000		82,000	85,000	49,000	60,000	452,000														423,000	441,000
Short-term debt																										0	200,000,000	[1]	200,000,000
Other long-term debt			140,000,000																											140,000,000																																						100,000,000	[1]
Total	3,612,112,000	3,147,227,000
Debt maturing within one year	$ 200,000,000	$ 651,929,000	$ 50,000,000	$ 466,935,000

[1] As of December 31, 2013 and 2012, there was $200.0 million and $651.9 million, respectively, of debt included within debt maturing within one year that is classified as a current liability in the consolidated statements of financial position.

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SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT Related-party Transactions (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
ITC Holdings Corp.
Condensed Financial Statements, Captions
Dividends from subsidiaries	$ 169,973,000	$ 127,412,000	$ 304,244,000
Return of capital from subsidiaries	96,120,000	91,399,000	228,600,000
ITCTransmission
Condensed Financial Statements, Captions
Tax payments from subsidiary under intercompany tax sharing agreement	39,100,000	18,900,000	51,600,000
MTH
Condensed Financial Statements, Captions
Tax payments from subsidiary under intercompany tax sharing agreement	30,000,000	17,600,000	23,300,000
ITC Midwest LLC
Condensed Financial Statements, Captions
Tax payments from subsidiary under intercompany tax sharing agreement	33,600,000	37,200,000	11,300,000
ITC Great Plains LLC
Condensed Financial Statements, Captions
Tax payments from subsidiary under intercompany tax sharing agreement	$ 9,400,000	$ 4,300,000	$ 0

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PROPERTY, PLANT AND EQUIPMENT (Tables)

12 Months Ended

Dec. 31, 2013

Public Utilities, Property, Plant and Equipment [Abstract]

Schedule of Public Utility Property, Plant, and Equipment

Property, plant and equipment — net consisted of the following at December 31, 2013 and 2012:

(In thousands)	2013			2012
Property, plant and equipment
Regulated Operating Subsidiaries:
Property, plant and equipment in service	$	5,641,240		$	4,779,833
Construction work in progress	423,433			501,847
Capital equipment inventory	75,470			86,882
Other	22,460			22,481
ITC Holdings and other	14,017			13,346
Total	6,176,620			5,404,389
Less: Accumulated depreciation and amortization	(1,330,094		)	(1,269,810		)
Property, plant and equipment — net	$	4,846,526		$	4,134,579

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EARNINGS PER SHARE (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Earnings Per Share, Basic and Diluted [Abstract]
Outstanding stock options and ESPP shares	1,723,276	1,603,429	2,100,056
Anti-dilutive stock options and ESPP shares	304,190	565,945	213,917

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SHARE-BASED COMPENSATION

12 Months Ended

Dec. 31, 2013

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

SHARE-BASED COMPENSATION

SHARE-BASED COMPENSATION

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 4,950,000 shares to employees, directors and consultants. The LTIP provides that no more than 3,250,000 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. The ESPP allows for the issuance of an aggregate of 180,000 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, 2013, 1,873,658 shares were available for future issuance under our LTIP and ESPP, including 1,723,276 shares issuable upon the exercise of outstanding stock options, of which 1,128,540 were vested.

We recorded share-based compensation in 2013, 2012 and 2011 as follows:

(In thousands)	2013		2012		2011
Operation and maintenance expenses	$	1,617	$	1,933	$	2,540
General and administrative expenses	9,318		8,057		7,524
Amounts capitalized to property, plant and equipment	4,731		5,632		5,327
Total share-based compensation	$	15,666	$	15,622	$	15,391
Total tax benefit recognized in the consolidated statement of operations	$	4,557	$	3,807	$	3,976

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, 2013, 2012 and 2011, we recognized the tax effects of the excess tax deductions as an increase in common stock of $4.3 million, $23.0 million and $28.1 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 2013 was as follows:

			Weighted
	Number of		Average
	Options		Exercise Price
Outstanding at January 1, 2013 (1,030,594 exercisable with a weighted average exercise price of $38.10)	1,603,429		$	49.02
Granted	310,111		87.93
Exercised	(166,338	)	49.09
Forfeited	(23,926	)	79.03
Outstanding at December 31, 2013 (1,128,540 exercisable with a weighted average exercise price of $42.98)	1,723,276		$	55.60

Grant date fair value of the stock options awards granted during 2013, 2012 and 2011 was determined using a Black-Scholes option pricing model. The following assumptions were used in determining the weighted average fair value per option:

	2013			2012			2011
	Option Grants			Option Grants			Option Grants
Weighted average grant date fair value per option	$	21.17		$	16.58		$	18.77
Weighted average expected volatility (a)	29.3		%	29.8		%	29.8		%
Weighted average risk-free interest rate	1.1		%	1.0		%	2.1		%
Weighted average expected term (b)	6 years			6 years			6 years
Weighted average expected dividend yield	1.72		%	1.99		%	1.86		%
Estimated fair value of underlying shares	$	87.93		$	70.76		$	72.15

____________________________

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

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

At December 31, 2013, the aggregate intrinsic value and the weighted average remaining contractual term for all outstanding options were approximately $69.3 million and 5.8 years, respectively. At December 31, 2013, the aggregate intrinsic value and the weighted average remaining contractual term for exercisable options were $59.6 million and 4.3 years, respectively. The aggregate intrinsic value of options exercised during 2013, 2012 and 2011 were $53.2 million, $53.2 million and $20.5 million, respectively. At December 31, 2013, the total unrecognized compensation cost related to the unvested options awards was $6.9 million and the weighted average period over which it is expected to be recognized was 1.9 years.

We estimate that 1,698,016 of the options outstanding at December 31, 2013 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, 2013 was $55.24 per share, $68.9 million and 5.8 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, 2013 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 2013 was as follows:

	Number of		Weighted
	Restricted		Average
	Stock		Grant Date
	Awards		Fair Value
Unvested restricted stock awards at January 1, 2013	523,350		$	62.63
Granted	128,192		88.27
Vested	(175,182	)	52.99
Forfeited	(14,038	)	76.13
Unvested restricted stock awards at December 31, 2013	462,322		$	72.97

The weighted average grant date fair value of restricted stock awarded during 2012 and 2011 was $71.65 and $71.27 per share, respectively. The aggregate fair value of restricted stock awards as of December 31, 2013 was $44.3 million. The aggregate fair value of restricted stock awards that vested during 2013, 2012 and 2011 was $15.8 million, $25.1 million and $20.7 million, respectively. At December 31, 2013, the total unrecognized compensation cost related to the restricted stock awards was $17.8 million and the weighted average period over which that cost is expected to be recognized was 2.2 years.

As of December 31, 2013, we estimate that 419,237 shares of the restricted shares outstanding at December 31, 2013 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 $72.60 per share, $40.2 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 2013, 2012 and 2011, employees purchased 25,699, 25,521 and 23,027 shares, respectively, resulting in proceeds from the sale of our common stock of $1.9 million, $1.6 million and $1.3 million, respectively, under the ESPP. The total share-based compensation amortization for the ESPP was $0.4 million, $0.4 million and $0.3 million for the years ended December 31, 2013, 2012 and 2011, respectively.

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DEBT (Tables)

12 Months Ended

Dec. 31, 2013

Debt Disclosure [Abstract]

Schedule of Debt

The following amounts were outstanding at December 31, 2013 and 2012:

(Amounts in thousands)	2013		2012
ITC Holdings 5.25% Senior Notes due July 15, 2013 (net of discount of $65) (a)	$	—	$	266,935
ITC Holdings 6.04% Senior Notes, Series A, due September 20, 2014 (a)	50,000		50,000
ITC Holdings 5.875% Senior Notes due September 30, 2016 (net of discount of $9 and $12, respectively)	254,991		254,988
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 $174 and $182, respectively)	254,826		254,818
ITC Holdings 6.05% Senior Notes due January 31, 2018 (net of discount of $644 and $802, respectively)	384,356		384,198
ITC Holdings 5.50% Senior Notes due January 15, 2020 (net of discount of $787 and $920, respectively)	199,213		199,080
ITC Holdings 4.05% Senior Notes due July 1, 2023 (net of discount of $677)	249,323		—
ITC Holdings 5.30% Senior Notes due July 1, 2043 (net of discount of $791)	299,209		—
ITC Holdings Term Loan Credit Agreement due August 23, 2013 (a)	—		200,000
ITC Holdings Term Loan Credit Agreement due September 30, 2016	140,000		—
ITC Holdings Revolving Credit Agreement due May 17, 2016	—		29,600
ITCTransmission 4.45% First Mortgage Bonds, Series A, due July 15, 2013 (net of discount of $6) (a)	—		184,994
ITCTransmission 6.125% First Mortgage Bonds, Series C, due March 31, 2036 (net of discount of $82 and $85, respectively)	99,918		99,915
ITCTransmission 5.75% First Mortgage Bonds, Series D, due April 1, 2018 (net of discount of $49 and $60, respectively)	99,951		99,940
ITCTransmission 4.625% First Mortgage Bonds, Series E, due August 15, 2043 (net of discount of $452)	284,548		—
ITCTransmission Revolving Credit Agreement due May 17, 2016	41,100		78,700
METC 5.75% Senior Secured Notes due December 10, 2015	175,000		175,000
METC 6.63% Senior Secured Notes due December 18, 2014 (a)	50,000		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 Revolving Credit Agreement due May 17, 2016	67,200		10,500
ITC Midwest 6.15% First Mortgage Bonds, Series A, due January 31, 2038 (net of discount of $423 and $441, respectively)	174,577		174,559
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		—
ITC Midwest Revolving Credit Agreement due May 31, 2017	111,000		115,300
ITC Great Plains Term Loan Credit Agreement due November 28, 2014 (a)	100,000		—
ITC Great Plains Revolving Credit Agreement due February 16, 2015	51,900		93,700
Total debt	$	3,612,112	$	3,147,227

____________________________

(a) As of December 31, 2013 and 2012, there was $200.0 million and $651.9 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.

Schedule of Maturities of Debt

The annual maturities of debt as of December 31, 2013 are as follows:

(In thousands)
2014	$	200,000
2015	226,900
2016	503,300
2017	201,000
2018	485,000
2019 and thereafter	2,000,000
Total	$	3,616,200

Schedule of Interest Rate Swap Agreements

A summary of the terminated interest rate swaps is provided below:

Interest Rate Swaps	Amount		Weighted Average Fixed Rate	Gain (Loss) on Derivative			Settlement Date
(amounts in millions)
10-year interest rate swaps	$	250.0	3.39%	$	(15.0	)	June 2013
30-year interest rate swaps	225.0		2.84%	26.2			June 2013
Total	$	475.0		$	11.2

Schedule of Revolving Credit Agreements

At December 31, 2013, ITC Holdings and its Regulated Operating Subsidiaries had the following unsecured revolving credit facilities available, each of which bears interest at a variable rate based on the prime rate or LIBOR (subject to adjustment based on credit rating):

(Amounts in millions)	Total Available Capacity		Outstanding Balance (a)		Unused Capacity		Weighted Average Interest Rate on Outstanding Balance		Commitment Fee Rate (b)		Original Term	Date of Maturity
Revolving Credit Agreements:
ITC Holdings	$	200.0	$	—	$	200.0	n/a	(c)	0.20	%	5 years	May 2016
ITCTransmission	100.0		41.1		58.9		1.3%		0.125	%	5 years	May 2016
METC	100.0		67.2		32.8		1.3%		0.125	%	5 years	May 2016
ITC Midwest	175.0		111.0		64.0		1.2%		0.10	%	5 years	May 2017
ITC Great Plains	150.0		51.9		98.1		1.9%		0.25	%	4 years	February 2015
Total	$	725.0	$	271.2	$	453.8

____________________________

(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) Amounts outstanding would bear interest at a rate equal to LIBOR plus an applicable margin of 1.50% or at a base rate, which is defined as the higher of the prime rate, 0.50% above the federal funds rate or 1% above the one month LIBOR, plus an applicable margin of 0.50%, subject to adjustments based on ITC Holdings’ credit rating.

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SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT Debt (Details) (USD $)	Dec. 31, 2013		Dec. 31, 2012
Maturities of Debt
2014	$ 200,000,000
2015	226,900,000
2016	503,300,000
2017	201,000,000
2018	485,000,000
2019 and thereafter	2,000,000,000
Total	3,616,200,000
Fair Value Disclosures [Abstract]
Fair value of long-term debt and debt maturing within one year, excluding revolving and term loan credit agreements	3,299,000,000		3,072,900,000
Book value of long-term debt and debt maturing within one year, excluding revolving and term loan credit agreements	3,100,900,000		2,619,400,000
Revolving credit agreement	271,200,000	[1]
Book value of revolving and term loan credit agreements	511,200,000		527,800,000
ITC Holdings Corp.
Maturities of Debt
2014	50,000,000
2015	0
2016	395,000,000
2017	50,000,000
2018	385,000,000
2019 and thereafter	1,005,000,000
Total	1,885,000,000
Fair Value Disclosures [Abstract]
Fair value of long-term debt and debt maturing within one year, excluding revolving and term loan credit agreements	1,864,700,000		1,707,200,000
Book value of long-term debt and debt maturing within one year, excluding revolving and term loan credit agreements	1,741,900,000		1,460,000,000
Other long-term debt	140,000,000
Revolving credit agreement	0	[1]
Book value of revolving and term loan credit agreements			$ 229,600,000

[1] Included within long-term debt.

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COMMITMENTS AND CONTINGENT LIABILITIES

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENT LIABILITIES

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 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

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.

Michigan Sales and Use Tax Audit

The Michigan Department of Treasury conducted a sales and use tax audit of ITCTransmission for the audit period April 1, 2005 through June 30, 2008 and has denied ITCTransmission’s use of the industrial processing exemption from use tax it has taken beginning January 1, 2007. ITCTransmission has certain administrative and judicial appeal rights.

ITCTransmission believes that its utilization of the industrial processing exemption is appropriate and intends to defend itself against the denial of such exemption. 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 the potential use tax liability associated with the exemptions taken by ITCTransmission through December 31, 2013 is estimated to be approximately $18.7 million, which includes approximately $3.8 million assessed for the audit period April 1, 2005 through June 30, 2008, including interest. ITCTransmission has not recorded this contingent liability as of December 31, 2013. However, in the event it becomes appropriate to record additional use tax liability relating to this matter, ITCTransmission 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. METC has also taken the industrial processing exemption, estimated to be approximately $11.3 million for periods still subject to audit; however, METC has not recorded any contingent liabilities as of December 31, 2013 associated with this matter. These higher use tax expenses would be included as components of net revenue requirements and resulting rates.

FERC Audit of ITC Midwest

Certain staff of the FERC (“FERC audit staff”) have conducted an audit of ITC Midwest’s compliance with certain of the FERC’s regulations and the conditions established in the 2007 FERC order approving the acquisition of the transmission assets of IP&L by ITC Midwest. In 2011, the FERC issued an order that identified certain findings and recommendations of FERC audit staff relating to specific aspects of the accounting treatment for the acquisition that requires adjustments to ITC Midwest’s annual revenue requirement calculations and corresponding refunds. In 2012, ITC Midwest filed a refund report with the FERC which included adjustments to ITC Midwest’s annual revenue requirement calculations and corresponding refunds. On January 30, 2013, the FERC accepted ITC Midwest’s refund report which included the amounts being refunded in 2014.

ITCTransmission and METC had applied an accounting treatment for their respective acquisitions similar to ITC Midwest, and on February 1, 2013, voluntarily filed compliance plans with FERC to address the findings raised with respect to the ITC Midwest audit. On July 5, 2013, the FERC accepted ITCTransmission’s and METC’s refund reports which included the amounts being refunded in 2014.

ITC Midwest, ITCTransmission and METC have recorded an aggregate regulatory liability for the refund and related interest of $13.1 million and $12.7 million as of December 31, 2013 and December 31, 2012, respectively, in the consolidated statements of financial position. The refund amounts were limited to 2010 and earlier periods. As a result of FERC’s acceptance of the refund reports, this matter is now closed.

Purchase Obligations and Leases

At December 31, 2013, we had purchase obligations of $100.2 million representing commitments for materials, services and equipment that had not been received as of December 31, 2013, 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 2014.

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 $0.8 million, $0.7 million and $0.7 million for the years ended December 31, 2013, 2012 and 2011, 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, 2013 were:

(In thousands)
2014	$	604
2015	237
2016	178
2017	180
2018 and thereafter	95
Total minimum lease payments	$	1,294

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 the primary beneficiary of the variable interest under the agreement. Additionally, 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.

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”), 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 from year to year thereafter until terminated by either party upon not less than one year prior written notice to the other party.

Project Commitment. In the Minnesota regulatory proceeding to approve ITC Midwest’s December 2007 acquisition of the transmission assets of IP&L, ITC Midwest agreed to build a certain project in Iowa, the 345 kV Salem-Hazelton line, and made a commitment to use commercially reasonable best efforts to complete the project prior to December 31, 2011. In the event ITC Midwest is found to have failed to meet this commitment, the allowed 12.38% rate of return on the actual equity portion of its capital structure would be reduced to 10.39% until such time as ITC Midwest completes the project, and ITC Midwest would refund with interest any amounts collected since the close date of the transaction that exceeded what would have been collected if the 10.39% return on equity had been used. Certain regulatory approvals were needed from the IUB before construction of the project could commence, but due to the IUB’s case schedule, these approvals were not received until the second quarter of 2011. As a result of the delay in the receipt of the necessary regulatory approvals, the project was not completed by December 31, 2011. We have notified the Minnesota Public Utilities Commission that the Salem-Hazleton line was placed into service on April 25, 2013, and requested confirmation from the commission that ITC Midwest has satisfied its commitment and that no refund is due as a result of the project not being completed by December 31, 2011. We believe we used commercially reasonable best efforts to meet the December 31, 2011 deadline, and therefore, we believe the likelihood of any material effect on the financial statements from this matter is remote.

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 have entered into a maintenance agreement (the “Midwest Energy Agreement”) dated as of June 25, 2012, pursuant to which Midwest Energy has agreed to perform various field operations and maintenance service related to ITC Great Plains facilities associated with the KETA project. The Midwest Energy Agreement has 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. Services must continue to be provided for at least six months subsequent to the termination date in any case.

Concentration of Credit Risk

Our credit risk is primarily with DTE Electric, Consumers Energy and IP&L, which were responsible for approximately 23.8%, 24.0% and 27.9%, respectively, or $221.0 million, $222.5 million and $259.4 million, respectively, of our consolidated billed revenues for the year ended December 31, 2013. These percentages and amounts of total billed revenues of DTE Electric, Consumers Energy and IP&L include the collection of 2011 revenue accruals and deferrals and exclude any amounts for the 2013 revenue accruals and deferrals that were included in our 2013 operating revenues, but will not be billed to our customers until 2015. 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 of the difference between billed revenues and operating revenues. 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 the SPP have implemented strict credit policies for its members’ customers, which include customers using our transmission systems. In general, if these customers do not maintain their investment grade credit rating or have a history of late payments, MISO and the SPP may require them to provide MISO and the SPP with a letter of credit or cash deposit equal to the highest monthly invoiced amount over the previous twelve months.

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INCOME TAXES Deferred Tax Assets and Liabilities (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Deferred Tax Assets and Liabilities
Property, plant and equipment	$ (459,983)		$ (378,196)
Goodwill	(117,493)		(102,994)
Pension and postretirement liabilities	11,864		9,706
State income tax NOLs (net of federal benefit)	16,573		11,759
Share-based compensation	12,040		10,281
Other — net	(3,530)		14,001
Net deferred tax liabilities	(545,713)		(437,058)
Gross deferred income tax liabilities	(674,172)		(572,088)
Gross deferred income tax assets	128,459		135,030
ADIT Deferral
Deferred Tax Assets and Liabilities
Deferred tax liabilities, regulatory assets	(14,945)	[1]	(14,852)	[1]
Net Revenue Accruals and Deferrals, Including Accrued Interest
Deferred Tax Assets and Liabilities
Deferred tax assets, regulatory assets and liabilities	23,504	[1]	28,121	[1]
METC LLC | Regulatory Deferrals
Deferred Tax Assets and Liabilities
Deferred tax liabilities, regulatory assets	$ (13,743)	[1]	$ (14,884)	[1]

[1] Described in Note 5.

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CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (Parentheticals) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Dividends declared per common share	$ 1.605	$ 1.460	$ 1.375

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CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (Parentheticals) (USD $) In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Property, plant and equipment, accumulated depreciation and amortization	$ 1,330,094	$ 1,269,810
Intangible assets, accumulated amortization	21,616	18,397
Deferred financing fees, accumulated amortization	$ 15,261	$ 17,838
Common stock, without par value	$ 0	$ 0
Common stock, shares authorized	100,000,000	100,000,000
Common stock, shares issued	52,500,265	52,248,514
Common stock, shares outstanding	52,500,265	52,248,514

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EARNINGS PER SHARE

12 Months Ended

Dec. 31, 2013

Earnings Per Share, Basic and Diluted [Abstract]

EARNINGS PER SHARE

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, 2013, 2012 and 2011 is presented in the following table:

	Year Ended December 31,
(In thousands, except per share and share data)	2013			2012			2011
Numerator:
Net income	$	233,506		$	187,876		$	171,685
Less: dividends declared — common and restricted shares	(84,104		)	(75,124		)	(70,305		)
Undistributed earnings	149,402			112,752			101,380
Percentage allocated to common shares (a)	99.1		%	98.7		%	98.3		%
Undistributed earnings — common shares	148,057			111,286			99,657
Add: dividends declared — common shares	83,351			74,202			69,200
Numerator for basic and diluted earnings per common share	$	231,408		$	185,488		$	168,857
Denominator:
Denominator for basic earnings per common share — weighted average common shares	51,912,128			50,820,838			50,289,905
Incremental shares for stock options and employee stock purchase plan — weighted average assumed conversion	429,540			742,557			788,918
Denominator for diluted earnings per common share — adjusted weighted average shares and assumed conversion	52,341,668			51,563,395			51,078,823
Per common share net income:
Basic	$	4.46		$	3.65		$	3.36
Diluted	$	4.42		$	3.60		$	3.31

____________________________

(a)	Weighted average common shares outstanding	51,912,128		50,820,838		50,289,905
	Weighted average restricted shares and deferred stock units
	(participating securities)	490,989		658,835		854,717
	Total	52,403,117		51,479,673		51,144,622
	Percentage allocated to common shares	99.1	%	98.7	%	98.3	%

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:

	2013	2012	2011
Outstanding stock options and ESPP shares (as of December 31)	1,723,276	1,603,429	2,100,056
Anti-dilutive stock options and ESPP shares (for the year ended December 31)	304,190	565,945	213,917

The preceding earnings per share and share data do not reflect the impact of the three-for-one stock split, which will be effective on February 28, 2014. See Note 20 for further information.

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SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT Condensed Statements of Financial Position (Parent Company Only) (Details) (USD $) In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Current assets
Cash and cash equivalents	$ 34,275		$ 26,187		$ 58,344		$ 95,109
Total current assets	191,538		198,226
Other assets
Deferred financing fees (net of accumulated amortization of $6,346 and $8,063, respectively)	25,585		19,293
Other	40,035		33,678
Total other assets	1,244,179		1,232,004
TOTAL ASSETS	6,282,243	[1]	5,564,809	[1]	4,823,366	[1]
Current liabilities
Accounts payable	111,145		123,022
Accrued payroll	21,930		20,740
Accrued interest	53,049		44,708
Debt maturing within one year	200,000		651,929
Other	27,047		40,287
Total current liabilities	499,379		1,003,311
Accrued pension and postretirement liabilities	53,704		53,243
Other	17,032		26,317
Long-term debt (net of discounts of $3,082 and $1,916, respectively)	3,412,112		2,495,298
STOCKHOLDERS’ EQUITY
Common stock, without par value, 100,000,000 shares authorized, 52,500,265 and 52,248,514 shares issued and outstanding at December 31, 2013 and 2012, respectively	1,014,435		989,334
Retained earnings	592,970		443,569
Accumulated other comprehensive income (loss)	6,327		(18,048)		(15,368)		1,188
Total stockholders’ equity	1,613,732		1,414,855
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	6,282,243		5,564,809
Balance Sheet Additional Disclosures
Deferred financing fees, accumulated amortization	15,261		17,838
Common stock, without par value	$ 0		$ 0
Common stock, shares authorized	100,000,000		100,000,000
Common stock, shares issued	52,500,265		52,248,514
Common stock, shares outstanding	52,500,265		52,248,514
ITC Holdings Corp.
Current assets
Cash and cash equivalents	26,853		22,546		49,240		71,384
Accounts receivable from subsidiaries	50,196		51,005
Prepaid assets	5,806		22,756
Other	1,496		4,775
Total current assets	84,351		101,082
Other assets
Investment in subsidiaries	3,450,989		3,052,902
Deferred income taxes	25,519		35,272
Deferred financing fees (net of accumulated amortization of $6,346 and $8,063, respectively)	11,241		7,308
Other	47,660		55,393
Total other assets	3,535,409		3,150,875
TOTAL ASSETS	3,619,760		3,251,957
Current liabilities
Accounts payable	6,300		8,594
Accrued payroll	21,930		20,740
Accrued interest	37,486		30,985
Derivative instruments	0		31,507
Debt maturing within one year	50,000		466,935
Other	3,583		1,484
Total current liabilities	119,299		560,245
Accrued pension and postretirement liabilities	53,704		53,243
Other	1,106		930
Long-term debt (net of discounts of $3,082 and $1,916, respectively)	1,831,918		1,222,684
STOCKHOLDERS’ EQUITY
Common stock, without par value, 100,000,000 shares authorized, 52,500,265 and 52,248,514 shares issued and outstanding at December 31, 2013 and 2012, respectively	1,014,435		989,334
Retained earnings	592,971		443,569
Accumulated other comprehensive income (loss)	6,327		(18,048)
Total stockholders’ equity	1,613,733		1,414,855
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	3,619,760		3,251,957
Balance Sheet Additional Disclosures
Deferred financing fees, accumulated amortization	6,346		8,063
Unamortized discount	$ 3,082		$ 1,916
Common stock, without par value	$ 0		$ 0
Common stock, shares authorized	100,000,000		100,000,000
Common stock, shares issued	52,500,265		52,248,514
Common stock, shares outstanding	52,500,265		52,248,514

[1] 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.

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SUPPLEMENTARY QUARTERLY FINANCIAL INFORMATION (Unaudited) (Details) (USD $)	3 Months Ended																12 Months Ended
	Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013		Dec. 31, 2012		Sep. 30, 2012		Jun. 30, 2012		Mar. 31, 2012		Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Selected Quarterly Financial Information [Abstract]
Operating revenues	$ 255,369,000	[1]	$ 238,782,000	[1]	$ 229,817,000	[1]	$ 217,304,000	[1]	$ 221,646,000	[1]	$ 214,801,000	[1]	$ 197,375,000	[1]	$ 196,713,000	[1]	$ 941,272,000	[1]	$ 830,535,000	[1]	$ 757,397,000
Operating income	141,364,000	[1]	130,822,000	[1]	110,994,000	[1]	112,881,000	[1]	113,328,000	[1]	113,354,000	[1]	98,483,000	[1]	105,894,000	[1]	496,061,000	[1]	431,059,000	[1]	397,752,000
NET INCOME	76,937,000	[1],[2]	58,984,000	[1],[2]	47,395,000	[1],[2]	50,190,000	[1],[2]	48,256,000	[1]	51,183,000	[1]	42,386,000	[1]	46,051,000	[1]	233,506,000	[1],[2]	187,876,000	[1]	171,685,000
Basic	$ 1.47	[1]	$ 1.12	[1]	$ 0.90	[1]	$ 0.96	[1]	$ 0.93	[1]	$ 0.99	[1]	$ 0.82	[1]	$ 0.90	[1]	$ 4.46	[1]	$ 3.65	[1]	$ 3.36
Diluted	$ 1.45	[1]	$ 1.12	[1]	$ 0.90	[1]	$ 0.95	[1]	$ 0.92	[1]	$ 0.98	[1]	$ 0.81	[1]	$ 0.88	[1]	$ 4.42	[1]	$ 3.60	[1]	$ 3.31
External Legal, Advisory and Financial Services Fees
Terminated Entergy Transaction
Entergy Transaction related expenses																	43,100,000		19,400,000		7,000,000
Tax benefit from Entergy Transaction	(13,100,000)	[3]
Internal Labor and Associated Costs
Terminated Entergy Transaction
Entergy Transaction related expenses																	$ 7,800,000		$ 7,100,000		$ 1,600,000

[1] During the years ended December 31, 2013 and 2012, we expensed external legal, advisory and financial services fees of $43.1 million and $19.4 million, respectively, and internal labor and related costs of approximately $7.8 million and $7.1 million, respectively, related to the Entergy Transaction. 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.

[2] 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 for the external costs related to the Entergy transaction incurred in 2013, 2012 and 2011 that originally were recorded as non-deductible for income tax provision purposes.

[3] 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 on the Entergy Transaction.

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Document and Entity Information Document (USD $) In Billions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Feb. 21, 2014	Jun. 30, 2013
Document and Entity Information [Abstract]
Entity Registrant Name	ITC Holdings Corp.
Entity Central Index Key	0001317630
Document Type	10-K
Trading Symbol	ITC
Document Period End Date	Dec. 31, 2013
Amendment Flag	false
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Common Stock, Shares Outstanding		52,522,301
Entity Public Float			$ 4.7

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INCOME TAXES

12 Months Ended

Dec. 31, 2013

Income Tax Disclosure [Abstract]

INCOME TAXES

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)	2013			2012			2011
Income tax expense at 35% statutory rate	$	123,329		$	103,778		$	93,252
State income taxes (net of federal benefit)	9,110			6,247			4,766
AFUDC equity	(9,715		)	(7,207		)	(5,292		)
Entergy Transaction expenses (a)	(5,614		)	4,113			1,501
Other — net	1,752			1,701			522
Total income tax provision	$	118,862		$	108,632		$	94,749

____________________________

(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 on the Entergy Transaction.

Components of the income tax provision were as follows:

(In thousands)	2013		2012		2011
Current income tax expense	$	42,159	$	41,347	$	63,952
Deferred income tax expense	76,094		66,710		33,266
Benefits of operating loss carryforward	609		575		2,169
Change in Michigan tax law	—		—		(4,638		)
Total income tax provision	$	118,862	$	108,632	$	94,749

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)	2013			2012
Property, plant and equipment	$	(459,983	)	$	(378,196	)
METC regulatory deferral (a)	(13,743		)	(14,884		)
Acquisition adjustments — ADIT deferrals (a)	(14,945		)	(14,852		)
Goodwill	(117,493		)	(102,994		)
Net revenue accruals and deferrals, including accrued interest (a)	23,504			28,121
Pension and postretirement liabilities	11,864			9,706
State income tax NOLs (net of federal benefit)	16,573			11,759
Share-based compensation	12,040			10,281
Other — net	(3,530		)	14,001
Net deferred tax liabilities	$	(545,713	)	$	(437,058	)
Gross deferred income tax liabilities	$	(674,172	)	$	(572,088	)
Gross deferred income tax assets	128,459			135,030
Net deferred tax liabilities	$	(545,713	)	$	(437,058	)

____________________________

(a)Described in Note 5.

We have state income tax net operating losses (“NOLs”) as of December 31, 2013, all of which we expect to use prior to their expiration. Our state income tax NOLs would expire beginning in 2027. We have recorded estimated state income tax NOL deferred tax assets of $16.6 millionand $11.8 million as of December 31, 2013 and 2012, respectively. We have additional state income tax NOLs of $6.1 million tax effected, net of federal benefit, 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.

Michigan Corporate Income Tax

On May25, 2011, the Michigan Business Tax was repealed and replaced with the Michigan Corporate Income Tax, effective January1, 2012. Under the CIT, we are taxed at a rate of 6.0% on federal taxable income apportioned to 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 remove deferred income tax balances recognized under the MBT and establish new deferred income tax balances under the CIT in the second quarter of 2011. The change in Michigan tax law resulted in a reduction of income tax provision of $4.6 million during 2011. Additionally, we recorded regulatory assets for this change in tax law as described in Note 5.

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STOCKHOLDERS' EQUITY Changes in Accumulated Other Comprehensive Income (Details) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Equity [Abstract]
Balance at the beginning of period	$ (18,048)	$ (15,368)	$ 1,188
Derivative instruments
Reclassification of net gain relating to interest rate cash flow hedges from AOCI to interest expense — net (net of tax of $436, $31 and $1 for the years ended December 31, 2013, 2012 and 2011, respectively)	(25)	67	97
Gain (loss) on interest rate swaps relating to interest rate cash flow hedges (net of tax of $15,652, $1,777 and $10,705 for the years ended December 31, 2013, 2012 and 2011, respectively)	24,329	(2,747)	(16,653)
Derivative instruments, net of tax	24,304	(2,680)	(16,556)
Available-for-sale securities
Unrealized gain on available-for-sale securities (net of tax of $46 for the year ended December 31, 2013)	71	0	0
Available-for-sale securities, net of tax	71	0	0
TOTAL OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX	24,375	(2,680)	(16,556)
Balance at the end of period	6,327	(18,048)	(15,368)
Changes in Accumulated Other Comprehensive Income, Parenthetical Disclosures
Reclassification of net gain relating to interest rate cash flow hedges from AOCI to interest expense — net, tax	436	31	1
Gain (loss) on interest rate swaps relating to interest rate cash flow hedges, tax	15,652	1,777	10,705
Unrealized gain on available-for-sale securities, tax	$ 46

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SEGMENT INFORMATION (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended																12 Months Ended
	Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013		Dec. 31, 2012		Sep. 30, 2012		Jun. 30, 2012		Mar. 31, 2012		Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Segment Reporting Information
Operating revenues	$ 255,369	[1]	$ 238,782	[1]	$ 229,817	[1]	$ 217,304	[1]	$ 221,646	[1]	$ 214,801	[1]	$ 197,375	[1]	$ 196,713	[1]	$ 941,272	[1]	$ 830,535	[1]	$ 757,397
Depreciation and amortization																	118,596		106,512		94,981
Interest expense — net																	168,319		155,734		146,936
Income before income taxes																	352,368		296,508		266,434
Income tax provision (benefit)																	118,862		108,632		94,749
NET INCOME	76,937	[1],[2]	58,984	[1],[2]	47,395	[1],[2]	50,190	[1],[2]	48,256	[1]	51,183	[1]	42,386	[1]	46,051	[1]	233,506	[1],[2]	187,876	[1]	171,685
Property, plant and equipment — net	4,846,526								4,134,579								4,846,526		4,134,579		3,415,823
Goodwill	950,163								950,163								950,163		950,163		950,163
Total assets	6,282,243	[3]							5,564,809	[3]							6,282,243	[3]	5,564,809	[3]	4,823,366	[3]
Capital expenditures																	821,588		802,763		556,931
Regulated Operating Subsidiaries
Segment Reporting Information
Operating revenues																	941,571		830,616		757,465
Depreciation and amortization																	117,924		105,841		94,520
Interest expense — net																	70,239		65,445		58,795
Income before income taxes																	515,327		422,074		367,628
Income tax provision (benefit)																	193,764		159,528		143,416
NET INCOME																	321,563		262,545		224,211
Property, plant and equipment — net	4,833,545								4,123,520								4,833,545		4,123,520		3,404,091
Goodwill	950,163								950,163								950,163		950,163		950,163
Total assets	6,174,888	[3]							5,440,401	[3]							6,174,888	[3]	5,440,401	[3]	4,711,274	[3]
Capital expenditures																	824,165		806,825		554,692
ITC Holdings and Other
Segment Reporting Information
Operating revenues																	567		607		486
Depreciation and amortization																	672		671		461
Interest expense — net																	98,660		90,289		88,609
Income before income taxes																	(162,959)		(125,566)		(101,194)
Income tax provision (benefit)																	(74,902)		(50,896)		(48,667)
NET INCOME																	233,506		187,876		171,685
Property, plant and equipment — net	12,981								11,059								12,981		11,059		11,732
Total assets	3,619,759	[3]							3,252,047	[3]							3,619,759	[3]	3,252,047	[3]	2,845,182	[3]
Capital expenditures																	2,208		243		7,633
Reconciliations and Eliminations
Segment Reporting Information
Operating revenues																	(866)		(688)		(554)
Interest expense — net																	(580)				(468)
NET INCOME																	(321,563)		(262,545)		(224,211)
Total assets	(3,512,404)	[3]							(3,127,639)	[3]							(3,512,404)	[3]	(3,127,639)	[3]	(2,733,090)	[3]
Capital expenditures																	$ (4,785)		$ (4,305)		$ (5,394)

[1] During the years ended December 31, 2013 and 2012, we expensed external legal, advisory and financial services fees of $43.1 million and $19.4 million, respectively, and internal labor and related costs of approximately $7.8 million and $7.1 million, respectively, related to the Entergy Transaction. 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.

[2] 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 for the external costs related to the Entergy transaction incurred in 2013, 2012 and 2011 that originally were recorded as non-deductible for income tax provision purposes.

[3] 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.

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CONSOLIDATED STATEMENTS OF OPERATIONS (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
OPERATING REVENUES	$ 941,272	[1]	$ 830,535	[1]	$ 757,397
OPERATING EXPENSES
Operation and maintenance	112,821		121,941		129,288
General and administrative	149,109		112,091		82,790
Depreciation and amortization	118,596		106,512		94,981
Taxes other than income taxes	65,824		59,701		53,430
Other operating (income) and expense — net	(1,139)		(769)		(844)
Total operating expenses	445,211		399,476		359,645
OPERATING INCOME	496,061	[1]	431,059	[1]	397,752
OTHER EXPENSES (INCOME)
Interest expense — net	168,319		155,734		146,936
Allowance for equity funds used during construction	(30,159)		(23,000)		(16,699)
Other income	(1,038)		(2,401)		(2,881)
Other expense	6,571		4,218		3,962
Total other expenses (income)	143,693		134,551		131,318
INCOME BEFORE INCOME TAXES	352,368		296,508		266,434
INCOME TAX PROVISION	118,862		108,632		94,749
NET INCOME	$ 233,506	[1],[2]	$ 187,876	[1]	$ 171,685
Basic earnings per common share	$ 4.46	[1]	$ 3.65	[1]	$ 3.36
Diluted earnings per common share	$ 4.42	[1]	$ 3.60	[1]	$ 3.31
Dividends declared per common share	$ 1.605		$ 1.460		$ 1.375

[1] During the years ended December 31, 2013 and 2012, we expensed external legal, advisory and financial services fees of $43.1 million and $19.4 million, respectively, and internal labor and related costs of approximately $7.8 million and $7.1 million, respectively, related to the Entergy Transaction. 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.

[2] 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 for the external costs related to the Entergy transaction incurred in 2013, 2012 and 2011 that originally were recorded as non-deductible for income tax provision purposes.

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REGULATORY MATTERS

12 Months Ended

Dec. 31, 2013

Regulated Operations [Abstract]

REGULATORY MATTERS

REGULATORY MATTERS

Start-up, Development and Pre-construction Regulatory Assets

As of December 31, 2013, we have recorded a total of $13.9 million of regulatory assets for start-up, development and pre-construction expenses, including associated 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.

Order on Formula Rate Protocols

On May 17, 2012, the FERC issued an order 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. On May 16, 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 to file revised formula rate protocols. On September 13, 2013, MISO and its member transmission owners, including our MISO Regulated Operating Subsidiaries, filed revised formula rate protocols which will 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. We do not expect the revised formula rate protocols to impact our results of operations, cash flows or financial condition.

Complaint of IP&L

On September 14, 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.

On July 18, 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. On August 14, 2013, MISO made the required compliance filing to revise ITC Midwest’s Attachment FF of the MISO Tariff. On August 16, 2013, 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.

Rate of Return on Equity and Capital Structure Complaint

On November 12, 2013, 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 (the “joint complainants”) filed a 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 (“TO”), including ITCTransmission, METC and ITC Midwest (currently set at 12.38%) to be unjust and unreasonable. The joint complainants are seeking a FERC order reducing the base rates of return on equity used in our formula transmission rate to 9.15%. The complaint also alleges 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 (ITCTransmission, METC and ITC Midwest use their actual structures, targeting 60% equity). The complaint asks FERC to institute a uniform capital structure for MISO TOs in which the assumed equity component does not exceed 50%. The complaint also alleges the return on equity adders currently approved for ITCTransmission for being a member of a RTO and for ITCTransmission and METC for being an independent transmission owner are no longer just and reasonable, and seeks to have them terminated. In the event a refund is required upon resolution of the complaint, the joint complainants are seeking a refund effective date of November 12, 2013.

On January 6, 2014, ITCTransmission, METC and ITC Midwest filed responses with the FERC to the Section 206 complaint (jointly with other MISO TOs and separate supplemental responses), and plan to vigorously defend the use of the current return on equity, the current capital structures targeting 60% equity, and the approved equity adders for RTO membership and independence. The responses seek dismissal of the complaint, or a denial of it on merits, with prejudice, as the joint complainants failed to meet their burden under Section 206 of the FPA to show that the current base rate of return on equity, approved capital structure targeting 60% equity and return on equity adders approved for ITCTransmission and METC are no longer just and reasonable. Further, the responses argue that the current return on equity along with the adders and approved capital structures encourage transmission investment are especially appropriate given the benefits of the independent transmission company model and RTO membership, and provide testimony to demonstrate that the current return on equity, including the adders and the use of capital structures targeting 60% equity, remain just and reasonable. We believe the likelihood of an unfavorable outcome of the complaint as it relates to the request to eliminate our approved return on equity adders and modify our existing capital structures is remote. While we believe an unfavorable outcome of the complaint request to reduce the base rates of return on equity is reasonably possible, we do not believe the range of potential loss would have been material to the consolidated financial statements as of and for the year ended December 31, 2013. However, an unfavorable resolution of this aspect of the complaint could have a material impact on our future results of operations, cash flows and financial condition.

FERC Audit Refund

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

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. The over- or under-collection typically results from differences between the projected revenue requirement used to establish the billing rate 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. 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.

The current and non-current regulatory assets are recorded in the consolidated statements of financial position in regulatory assets — revenue accruals, including accrued interest and other non-current assets, respectively. The current and non-current regulatory liabilities are recorded in regulatory liabilities — revenue deferrals, including accrued interest. 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, 2013:

(In thousands)	Total
Balance as of December 31, 2012	$	(72,168	)
Net refund of 2011 revenue deferrals and accruals, including accrued interest	47,061
Net revenue deferral for the year ended December 31, 2013	(32,782		)
Net accrued interest payable for the year ended December 31, 2013	(2,307		)
Balance as of December 31, 2013	$	(60,196	)

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

(In thousands)	Total
Current assets	$	6,334
Non-current assets — other	3,037
Current liabilities	(33,120		)
Non-current liabilities	(36,447		)
Balance as of December 31, 2013	$	(60,196	)

ITC Midwest’s Rate Discount

As part of the orders by the Iowa Utility Board (“IUB”) and the Minnesota Public Service 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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RECENT ACCOUNTING PRONOUNCEMENTS

12 Months Ended

Dec. 31, 2013

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

RECENT ACCOUNTING PRONOUNCEMENTS

RECENT ACCOUNTING PRONOUNCEMENTS

Presentation of Comprehensive Income

The guidance set forth by the FASB has been updated with respect to the presentation of comprehensive income in financial statements. Under this guidance, we are required to (1) disclose the changes in accumulated other comprehensive income (“AOCI”) by component and (2) disclose the effects on the line items of net income of significant amounts reclassified out of AOCI. We adopted this guidance as of January 1, 2013. For the year ended December 31, 2013, the requirements under (1) above are presented in the consolidated statements of comprehensive income and the requirements under (2) above are disclosed in Note 13 of this Form 10-K.

Balance Sheet Offsetting Requirements

The FASB has issued guidance to clarify the disclosure requirements regarding the nature of an entity’s rights of offset and related arrangements associated with its financial instruments and derivative instruments. The guidance requires entities to disclose, at a minimum, the following information in tabular format, separately for assets and liabilities: (a) the gross amounts of those recognized assets and those recognized liabilities; (b) the amounts offset to determine the net amounts presented in the statement of financial position; (c) the net amounts presented in the statement of financial position; (d) the amounts subject to an enforceable master netting arrangement or similar agreement; and (e) the net amount after deducting the amounts in (d) from the amounts in (c). We adopted this guidance as of January 1, 2013. As of December 31, 2013, we did not have any material assets or liabilities that were subject to the new disclosure requirements.

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JOINTLY OWNED UTILITY PLANT/COORDINATED SERVICES

12 Months Ended

Dec. 31, 2013

Regulated Operations [Abstract]

JOINTLY OWNED UTILITY PLANT/COORDINATED SERVICES

JOINTLY OWNED UTILITY PLANT/COORDINATED SERVICES

Our MISO Regulated Operating Subsidiaries have agreements with other utilities for the joint ownership of substation assets and transmission lines. We account for these jointly owned assets by recording property, plant and equipment for our percentage of ownership interest. Various agreements provide the authority for construction of capital improvements and 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 MISO 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, 2013:

	Net		Construction
(In thousands)	Investments (a)		Work in Progress
Substations	$	27,345	$	3,461
Lines	93,157		3,225
Total	$	120,502	$	6,686

____________________________

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

ITCTransmission

The Michigan Public Power Agency (the “MPPA”) has a 50.4% ownership interest in two ITCTransmission 345 kV transmission lines. ITCTransmission’s net investment in these two lines including jointly owned lines under construction totaled $25.1 million as of December 31, 2013. The MPPA’s ownership portion entitles them to approximately 234 MW of network transmission service over the ITCTransmission system. An Ownership and Operating Agreement with the MPPA provides ITCTransmission with authority for construction of capital improvements and for the operation and management of the transmission lines. The MPPA 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, 2013, METC had net investments in jointly owned assets within substations including jointly owned assets under construction totaling $13.3 million of which METC’s ownership percentages for these jointly owned substation assets ranged from 6.3% to 92.0%. In addition, the MPPA, the Wolverine Power Supply Cooperative, Inc. (the “WPSC”) and the Michigan South Central Power Agency, (the “MSCPA”), each have an ownership interest in several METC 345 kV transmission lines. This ownership entitles the MPPA, WPSC and MSCPA to approximately 608 MW of network transmission service over the METC transmission system. As of December 31, 2013, METC had net investments in jointly shared transmission lines totaling $41.1 million of which METC’s ownership percentages for these jointly owned lines ranged from 35.5% to 64.8%.

ITC Midwest

ITC Midwest has joint sharing of several substations and transmission lines with various parties. As of December 31, 2013, ITC Midwest had net investments in jointly shared substations facilities including jointly shared substations facilities under construction totaling $17.5 million of which ITC Midwest’s ownership percentages for these jointly owned substations facilities ranged from 28.0% to 80.0%. As of December 31, 2013, ITC Midwest had net investments in jointly shared transmission lines totaling $30.3 million of which ITC Midwest’s ownership percentage for these jointly owned lines ranged from 48.0% to 80.0%.

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RETIREMENT BENEFITS AND ASSETS HELD IN TRUST

12 Months Ended

Dec. 31, 2013

Compensation and Retirement Disclosure [Abstract]

RETIREMENT BENEFITS AND ASSETS HELD IN TRUST

RETIREMENT BENEFITS AND ASSETS HELD IN TRUST

Retirement Plan Benefits

We have a qualified retirement plan for eligible employees, comprised of a traditional final average pay plan and a cash balance plan. The traditional final average pay plan is noncontributory, covers select employees, and provides retirement benefits based on the employees’ 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. While we are obligated to fund the retirement plan by contributing the minimum amount required by the Employee Retirement Income Security Act of 1974, as amended, it is our practice to contribute the maximum allowable amount as defined by section 404 of the Internal Revenue Code. We made contributions of $6.9 million, $7.0 million and $3.6 million to the retirement plan in 2013, 2012 and 2011, respectively, although we had no minimum funding requirements. We expect to contribute up to $8.6 million to the retirement plan relating to the 2013 plan year in 2014.

We have also established two supplemental nonqualified, noncontributory, retirement benefit plans (“supplemental benefit plans”) for selected management employees. The plans provide for benefits that supplement those provided by our other retirement plans. The obligations under these supplemental nonqualified plans are included in the pension benefit obligation calculations below. The investments in trust for the supplemental nonqualified retirement plans of $21.1 million and $22.4 million at December 31, 2013 and 2012, respectively, are not included in the pension plan asset amounts presented below, but are included in other assets on our consolidated statement of financial position. For the years ended December 31, 2013, 2012 and 2011, we contributed $0.6 million, $4.7 million and $3.1 million, respectively, to these supplemental nonqualified, noncontributory, retirement 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 and $2.2 million in 2012 and 2011, respectively, were 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, 2013, all of our investments held in the supplemental benefit plan were classified as available-for-sale securities and the 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	2013		2012
Fixed income securities	47.7	%	48.4	%
Equity securities	52.3	%	51.6	%
Total	100.0	%	100.0	%

Net pension cost for 2013, 2012 and 2011 includes the following components:

(In thousands)	2013			2012			2011
Service cost	$	5,261		$	4,160		$	3,585
Interest cost	2,792			2,590			2,458
Expected return on plan assets	(2,868		)	(2,277		)	(1,896		)
Amortization of prior service credit	(42		)	(42		)	(42		)
Amortization of unrecognized loss	2,714			3,470			2,607
Net pension cost	$	7,857		$	7,901		$	6,712

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, 2013 and 2012:

(In thousands)	2013			2012
Change in Benefit Obligation:
Beginning projected benefit obligation	$	(72,400	)	$	(56,069	)
Service cost	(5,261		)	(4,160		)
Interest cost	(2,792		)	(2,590		)
Actuarial net gain (loss)	6,161			(10,481		)
Benefits paid	824			900
Ending projected benefit obligation	$	(73,468	)	$	(72,400	)
Change in Plans’ Assets:
Beginning plan assets at fair value	$	38,130		$	28,276
Actual return on plan assets	4,650			3,331
Employer contributions	6,938			7,023
Benefits paid	(824		)	(500		)
Ending plan assets at fair value	$	48,894		$	38,130
Funded status, underfunded	$	(24,574	)	$	(34,270	)
Accumulated benefit obligation	$	(61,832	)	$	(55,649	)
Amounts recorded as:
Funded Status:
Accrued pension liabilities	$	(35,003	)	$	(35,899	)
Pension assets — other assets — other	10,429			1,629
Total	$	(24,574	)	$	(34,270	)
Accumulated benefit obligation:
Qualified defined benefit retirement plan	$	(36,033	)	$	(33,051	)
Supplemental nonqualified retirement plans	(25,799		)	(22,598		)
Total	$	(61,832	)	$	(55,649	)
Unrecognized Amounts in Other Regulatory Assets:
Net actuarial loss	$	12,787		$	23,444
Prior service credit	(17		)	(59		)
Total	$	12,770		$	23,385

The unrecognized amounts that otherwise would have been charged and/or credited to accumulated other comprehensive income associated with the guidance for employers’ accounting for pensions 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.

Actuarial assumptions used to determine the benefit obligation for 2013, 2012 and 2011 are listed below:

	2013	2012	2011
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%

Actuarial assumptions used to determine the benefit cost for 2013, 2012 and 2011 are listed below:

	2013	2012	2011
Discount rate	3.70 - 4.45%	4.50 - 5.00%	5.17 - 5.67%
Annual rate of salary increases	5.00 - 6.00%	5.00 - 6.00%	5.00 - 6.00%
Expected long-term rate of return on plan assets	7.00%	7.25%	7.25%

At December 31, 2013, the projected benefit payments for the defined benefit retirement plans calculated using the same assumptions as those used to calculate the benefit obligation described above are listed below:

(In thousands)
2014	$	1,507
2015	1,762
2016	1,661
2017	5,250
2018	5,657
2019 through 2023	33,361

Investment Objectives and Fair Value Measurement

The general investment objectives of the qualified retirement 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 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, 2013 and 2012, there were no transfers between levels.

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 fair value measurement of the retirement plan assets as of December 31, 2012, 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:
Pooled separate accounts — U.S. equity securities	$	—	$	15,702	$	—
Pooled separate accounts — international equity securities	—		3,979		—
Pooled separate accounts — fixed income securities	—		15,824		—
Guaranteed deposit fund	—		2,625		—
Total	$	—	$	38,130	$	—

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 pooled separate accounts are valued at their estimated fair value by aggregating our proportionate share of the fair value of the underlying securities held by the accounts. The pooled separate accounts investments consist primarily of underlying publicly traded debt and equity securities for which market prices are readily available. 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 employees who may become eligible for these benefits. We contributed $1.5 million, $4.4 million and $3.4 million to the postretirement benefit plan in 2013, 2012 and 2011, respectively. We expect to contribute up to $3.0 million to the plan in 2014.

The plan assets consisted of the following assets by category:

Asset Category	2013		2012
Fixed income securities	46.6	%	49.8	%
Equity securities	53.4	%	50.2	%
Total	100.0	%	100.0	%

Our measurement of the accumulated postretirement benefit obligation as of December 31, 2013 and 2012 does not reflect the potential receipt of any subsidies under the Medicare Prescription Drug, Improvement and Modernization Act of 2003.

Net postretirement cost for 2013, 2012 and 2011 includes the following components:

(In thousands)	2013			2012			2011
Service cost	$	5,774		$	5,433		$	3,431
Interest cost	1,562			1,552			1,285
Expected return on plan assets	(1,415		)	(1,016		)	(737		)
Amortization of prior service cost	—			125			313
Amortization of unrecognized loss	220			534			220
Net postretirement cost	$	6,141		$	6,628		$	4,512

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, 2013 and 2012:

(In thousands)	2013			2012
Change in Benefit Obligation:
Beginning accumulated postretirement obligation	$	(37,015	)	$	(30,679	)
Service cost	(5,774		)	(5,433		)
Interest cost	(1,562		)	(1,552		)
Actuarial net gain	1,491			474
Benefits paid	154			175
Ending accumulated postretirement obligation	$	(42,706	)	$	(37,015	)
Change in Plan’s Assets:
Beginning plan assets at fair value	$	19,670		$	13,549
Actual return on plan assets	2,857			1,747
Employer contributions	1,477			4,374
Employer provided retiree premiums	154			175
Benefits paid	(154		)	(175		)
Ending plan assets at fair value	$	24,004		$	19,670
Funded status, underfunded	$	(18,702	)	$	(17,345	)
Amounts recorded as:
Funded Status:
Accrued postretirement liabilities	$	(18,702	)	$	(17,345	)
Total	$	(18,702	)	$	(17,345	)
Unrecognized Amounts in Other Regulatory Assets:
Net actuarial loss	$	2,309		$	5,461
Prior service credit	—			—
Total	$	2,309		$	5,461

The unrecognized amounts that otherwise would have been charged and or credited to accumulated other comprehensive income associated with the guidance for employers’ accounting for pensions are recorded as a regulatory asset on our consolidated statements of financial position. The amounts recorded as a regulatory asset represent a net periodic benefit cost to be recognized in our operating income in future periods.

Actuarial assumptions used to determine the benefit obligation for 2013, 2012 and 2011 are as follows:

	2013	2012	2011
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
Annual rate of increase in dental benefit costs	5.00%	5.00%	5.00%

Actuarial assumptions used to determine the benefit cost for 2013, 2012 and 2011 are as follows:

	2013	2012	2011
Discount rate	4.20%	5.00%	5.49%
Annual rate of salary increases	5.00%	5.00%	5.00%
Health care cost trend rate assumed for next year	8.00%	9.00%	9.00%
Rate to which the cost trend rate is assumed to decline	5.00%	5.00%	5.00%
Expected long-term rate of return on plan assets	7.00%	7.25%	7.25%
Year that the rate reaches the ultimate trend rate	2017	2017	2017

At December 31, 2013, 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 listed below:

(In thousands)
2014	$	376
2015	482
2016	599
2017	766
2018	1,184
2019 through 2023	12,401

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 2013 and the postretirement benefit obligation at December 31, 2013:

	One-Percentage-		One-Percentage-
(In thousands)	Point Increase		Point Decrease
Effect on total of service and interest cost	$	1,400	$	(1,096	)
Effect on postretirement benefit obligation	7,449		(5,921		)

Investment Objectives and Fair Value Measurement

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

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

The measurement of fair value is based on a three-tier hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. Changes in economic conditions or model-based valuation techniques may require the transfer of financial instruments from one fair value level to another. In such instances, the transfer is reported at the beginning of the reporting period. For the years ended December 31, 2013 and 2012, there were no transfers between levels.

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	$	—

The fair value measurement of the other postretirement benefit plan assets as of December 31, 2012, 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	$	16	$	—	$	—
Pooled separate accounts — U.S. equity securities	—		2,131		—
Pooled separate accounts — international equity securities	—		529		—
Pooled separate accounts — fixed income securities	—		2,222		—
Mutual funds — equity securities	7,214		—		—
Mutual funds — fixed income securities	7,117		—		—
Guaranteed deposit fund	—		441		—
Total	$	14,347	$	5,323	$	—

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 pooled separate accounts are valued at their estimated fair value by aggregating our proportionate share of the fair value of the underlying securities held by the accounts. The pooled separate accounts investments consist primarily of underlying publicly traded debt and equity securities for which market prices are readily available. 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.

Defined Contribution Plan

We also sponsor a defined contribution retirement savings plan. Participation in this plan is available to substantially all employees. We match employee contributions up to certain predefined limits based upon eligible compensation and the employee’s contribution rate. The cost of this plan was $4.5 million, $3.8 million and $3.4 million in 2013, 2012 and 2011, respectively.

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SHARE-BASED COMPENSATION Assumptions (Details) (Stock Options, USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award
Weighted average grant date fair value per option	$ 21.17		$ 16.58		$ 18.77
Weighted average expected volatility	29.30%	[1]	29.80%	[1]	29.80%	[1]
Weighted average risk-free interest rate	1.10%		1.00%		2.10%
Weighted average expected term (in years)	6	[2]	6	[2]	6	[2]
Weighted average expected dividend yield	1.72%		1.99%		1.86%
Estimated fair value of underlying shares	$ 87.93		$ 70.76		$ 72.15

[1] We estimated volatility using the historical volatility of our stock.

[2] 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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PROPERTY, PLANT AND EQUIPMENT

12 Months Ended

Dec. 31, 2013

Public Utilities, Property, Plant and Equipment [Abstract]

PROPERTY, PLANT AND EQUIPMENT

PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment — net consisted of the following at December 31, 2013 and 2012:

(In thousands)	2013			2012
Property, plant and equipment
Regulated Operating Subsidiaries:
Property, plant and equipment in service	$	5,641,240		$	4,779,833
Construction work in progress	423,433			501,847
Capital equipment inventory	75,470			86,882
Other	22,460			22,481
ITC Holdings and other	14,017			13,346
Total	6,176,620			5,404,389
Less: Accumulated depreciation and amortization	(1,330,094		)	(1,269,810		)
Property, plant and equipment — net	$	4,846,526		$	4,134,579

Additions to property, plant and equipment in service and construction work in progress during 2013 and 2012 were due primarily for projects to upgrade or replace existing transmission plant to improve the reliability of our transmission systems in addition to generator interconnections and our ongoing development projects.

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DEBT Annual Maturities (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013
Maturities of Debt
2014	$ 200,000
2015	226,900
2016	503,300
2017	201,000
2018	485,000
2019 and thereafter	2,000,000
Total	$ 3,616,200

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REGULATORY ASSETS AND LIABILITIES

12 Months Ended

Dec. 31, 2013

Regulatory Assets and Liabilities Disclosure [Abstract]

REGULATORY ASSETS AND LIABILITIES

REGULATORY ASSETS AND LIABILITIES

Regulatory Assets

The following table summarizes the regulatory asset balances at December 31, 2013 and 2012:

(In thousands)	2013		2012
Regulatory Assets:
Revenue accruals:
Current (including accrued interest of $114 and $131 as of December 31, 2013 and 2012, respectively)	$	6,334	$	7,489
Non-current (including accrued interest of $27 and $17 as of December 31, 2013 and 2012, respectively)	3,037		2,719
Other:
ITCTransmission ADIT Deferral (net of accumulated amortization of $32,826 and $29,796 as of December 31, 2013 and 2012, respectively)	27,776		30,806
METC ADIT Deferral (net of accumulated amortization of $16,511 and $14,152 as of December 31, 2013 and 2012, respectively)	25,945		28,304
METC Regulatory Deferrals (net of accumulated amortization of $5,400 and $4,628 as of December 31, 2013 and 2012, respectively)	10,029		10,800
Income taxes recoverable related to AFUDC equity	75,798		57,135
ITC Great Plains start-up, development and pre-construction	13,916		14,117
Pensions and postretirement	15,079		28,847
Income taxes recoverable related to implementation of the Michigan Corporate Income Tax	8,869		8,869
Other	1,656		1,500
Total	$	188,439	$	190,586

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 2013, 2012 and 2011, 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 2013, 2012 and 2011, which is included in depreciation and amortization and recovered through METC’s cost-based formula rate template.

METC Regulatory Deferrals

METC has deferred, as a regulatory asset, depreciation and related interest expense associated with new transmission assets placed in service from January 1, 2001 through December 31, 2005 that were included on METC’s balance sheet at the time 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 2013, 2012 and 2011, 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 $8.2 million as of December 31, 2013, 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 theMichigan Corporate Income Tax

On May 25, 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 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. Recovery of the Michigan CIT regulatory asset requires FERC authorization upon ITC Holdings making an additional filing under Section 205 of the FPA to demonstrate that the costs to be recovered are just and reasonable. 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.

Regulatory Liabilities

The following table summarizes the regulatory liability balances at December 31, 2013 and 2012:

(In thousands)	2013		2012
Regulatory Liabilities:
Revenue deferrals (a):
Current (including accrued interest of $1,535 and $2,492 as of December 31, 2013 and 2012, respectively)	$	33,120	$	53,763
Non-current (including accrued interest of $581 and $473 as of December 31, 2013 and 2012, respectively)	36,447		28,613
Accrued asset removal costs	67,571		75,477
FERC audit refund (including accrued interest of $2,095 and $1,679 as of December 31, 2013 and 2012, respectively) (b)	13,067		12,651
Other (c)	2,968		—
Total	$	153,173	$	170,504

____________________________

(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.” As of December 31, 2013 and 2012, the FERC audit refund was recorded in the consolidated statements of financial position in other current liabilities and other liabilities, respectively.

(c) As of December 31, 2013, amount was recorded in other liabilities in the consolidated statements of financial position.

Accrued Asset Removal Costs

The carrying amount of the accrued asset removal costs represents the cumulative amount collected from customers to cover the estimated future costs to remove property, plant and equipment at retirement. 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. In addition, the regulatory liability is also adjusted for timing differences between when we recover legal asset retirement obligations in our rates and when we would recognize these costs 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 asset retirement obligations under the standards set forth by the FASB, within accumulated depreciation for rate-making purposes, which is a reduction to rate base.

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GOODWILL AND INTANGIBLE ASSETS

12 Months Ended

Dec. 31, 2013

Goodwill and Intangible Assets Disclosure [Abstract]

GOODWILL AND INTANGIBLE ASSETS

GOODWILL AND INTANGIBLE ASSETS

Goodwill

At December 31, 2013 and 2012, 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, 2013 and 2012 is $25.7 million and $27.7 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, 2013 and 2012 is $11.5 million and $12.6 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 made 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 is $12.1 million and $8.2 million (net of accumulated amortization of $0.4 million and $0.3 million, respectively) as of December 31, 2013 and 2012, respectively. The amortization period for these intangible assets is 50 years.

During each of the years ended December 31, 2013, 2012 and 2011, we recognized $3.2 million, $3.1 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, 2013 to be as follows:

(In thousands)
2014	$	3,276
2015	3,276
2016	3,276
2017	3,276
2018	3,276
2019 and thereafter	32,948
Total	$	49,328

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DEBT

12 Months Ended

Dec. 31, 2013

Debt Disclosure [Abstract]

DEBT

DEBT

The following amounts were outstanding at December 31, 2013 and 2012:

(Amounts in thousands)	2013		2012
ITC Holdings 5.25% Senior Notes due July 15, 2013 (net of discount of $65) (a)	$	—	$	266,935
ITC Holdings 6.04% Senior Notes, Series A, due September 20, 2014 (a)	50,000		50,000
ITC Holdings 5.875% Senior Notes due September 30, 2016 (net of discount of $9 and $12, respectively)	254,991		254,988
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 $174 and $182, respectively)	254,826		254,818
ITC Holdings 6.05% Senior Notes due January 31, 2018 (net of discount of $644 and $802, respectively)	384,356		384,198
ITC Holdings 5.50% Senior Notes due January 15, 2020 (net of discount of $787 and $920, respectively)	199,213		199,080
ITC Holdings 4.05% Senior Notes due July 1, 2023 (net of discount of $677)	249,323		—
ITC Holdings 5.30% Senior Notes due July 1, 2043 (net of discount of $791)	299,209		—
ITC Holdings Term Loan Credit Agreement due August 23, 2013 (a)	—		200,000
ITC Holdings Term Loan Credit Agreement due September 30, 2016	140,000		—
ITC Holdings Revolving Credit Agreement due May 17, 2016	—		29,600
ITCTransmission 4.45% First Mortgage Bonds, Series A, due July 15, 2013 (net of discount of $6) (a)	—		184,994
ITCTransmission 6.125% First Mortgage Bonds, Series C, due March 31, 2036 (net of discount of $82 and $85, respectively)	99,918		99,915
ITCTransmission 5.75% First Mortgage Bonds, Series D, due April 1, 2018 (net of discount of $49 and $60, respectively)	99,951		99,940
ITCTransmission 4.625% First Mortgage Bonds, Series E, due August 15, 2043 (net of discount of $452)	284,548		—
ITCTransmission Revolving Credit Agreement due May 17, 2016	41,100		78,700
METC 5.75% Senior Secured Notes due December 10, 2015	175,000		175,000
METC 6.63% Senior Secured Notes due December 18, 2014 (a)	50,000		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 Revolving Credit Agreement due May 17, 2016	67,200		10,500
ITC Midwest 6.15% First Mortgage Bonds, Series A, due January 31, 2038 (net of discount of $423 and $441, respectively)	174,577		174,559
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		—
ITC Midwest Revolving Credit Agreement due May 31, 2017	111,000		115,300
ITC Great Plains Term Loan Credit Agreement due November 28, 2014 (a)	100,000		—
ITC Great Plains Revolving Credit Agreement due February 16, 2015	51,900		93,700
Total debt	$	3,612,112	$	3,147,227

____________________________

(a) As of December 31, 2013 and 2012, there was $200.0 million and $651.9 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.

The annual maturities of debt as of December 31, 2013 are as follows:

(In thousands)
2014	$	200,000
2015	226,900
2016	503,300
2017	201,000
2018	485,000
2019 and thereafter	2,000,000
Total	$	3,616,200

ITC Holdings

Term Loan Credit Agreements

On August 23, 2012, ITC Holdings entered into an unsecured, unguaranteed term loan credit agreement (the “2012 Term Loan”), under which ITC Holdings borrowed the maximum of $200.0 million available under the agreement. This borrowing was repaid in full as of December 31, 2013.

On February 15, 2013, ITC Holdings entered into an unsecured, unguaranteed term loan credit agreement (the “February 2013 Term Loan”), under which ITC Holdings originally borrowed the maximum of $250.0 million available under the agreement. The proceeds were used for general corporate purposes, including the repayment of borrowings under the ITC Holdings’ revolving credit agreement. This borrowing was repaid in full as of December 31, 2013.

On December 20, 2013, ITC Holdings entered into an unsecured, unguaranteed term loan credit agreement (the “December 2013 Term Loan”) with a borrowing capacity of $200.0 million, under which ITC Holdings borrowed $140.0 million. The proceeds were used for general corporate purposes, including the repayment of borrowings under the ITC Holdings’ revolving credit agreement. The December 2013 Term Loan is scheduled to mature on September 30, 2016. The weighted-average interest rate on the borrowing outstanding under this agreement was 1.3% at December 31, 2013.

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, the $200.0 million borrowed under the 2012 Term Loan, a portion of the amount borrowed under the February 2013 Term Loan and for general corporate purposes. The ITC Holdings Senior Notes are issued under its indenture. All issuances of ITC Holdings Senior Notes are unsecured.

ITCTransmission

Term Loan Credit Agreement

On July 11, 2013, ITCTransmission entered into an unsecured, unguaranteed term loan credit agreement due July 14, 2014, under which ITCTransmission borrowed the maximum of $185.0 million upon entering the agreement. The proceeds were used to repay its $185.0 million of 4.45% First Mortgage Bonds, Series A, due July 15, 2013. This borrowing was repaid in full as of December 31, 2013.

First Mortgage Bonds

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. ITCTransmission’s First Mortgage Bonds are issued under its First Mortgage and Deed of Trust and secured by a first mortgage lien on substantially all of its property.

METC

Senior Secured Notes

On October 26, 2012, METC issued $75.0 million aggregate principal amount of its 3.98% Senior Secured Notes, due October 26, 2042 (the “METC Senior Secured Notes”). The proceeds were used primarily to refinance existing indebtedness, fund capital expenditures and for general corporate purposes. The METC Senior Secured Notes are secured by a first mortgage lien on substantially all of its real property and tangible personal property.

Term Loan Credit Agreement

On January 31, 2014, METC entered into an unsecured, unguaranteed term loan credit agreement, 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. The term loan is scheduled to mature on February 2, 2015. Borrowings outstanding under the term loan will bear interest at variable rates comparable to our other term loan borrowings.

ITC Midwest

ITC Midwest closed on the $100.0 million of 3.50% First Mortgage Bonds, Series E, due January 2027 on January 19, 2012. The proceeds from the issuance were used to refinance existing indebtedness, partially fund capital expenditures and for general corporate purposes.

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

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. The weighted average interest rate on the borrowings outstanding under the term loan was 1.0% at December 31, 2013.

Derivative Instruments and Hedging Activities

We may use derivative financial instruments, including interest rate swap contracts, to manage our exposure to fluctuations in interest rates. The use of these financial instruments mitigates exposure to these risks and the variability of our operating results. We are not a party to leveraged derivatives and do not enter into derivative financial instruments for trading or speculative purposes. As of December 31, 2012, we held $175.0 million and $50.0 million of 10-year and 30-year interest rate swaps, respectively, with a weighted average fixed rate of 3.99% and 2.59%, respectively, associated with forecasted future issuance of fixed rate debt. In 2013, we settled and terminated $250.0 million and $225.0 million of 10-year and 30-year term interest rate swaps, respectively, 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	Gain (Loss) on Derivative			Settlement Date
(amounts in millions)
10-year interest rate swaps	$	250.0	3.39%	$	(15.0	)	June 2013
30-year interest rate swaps	225.0		2.84%	26.2			June 2013
Total	$	475.0		$	11.2

The interest rate swaps qualified for hedge accounting treatment and the net gain of $11.2 million was recorded net of tax in AOCI during 2013. This amount is being amortized as a component of interest expense over the lives of the related debt.

We did not have any outstanding derivative financial instruments as of December 31, 2013.

Revolving Credit Agreements

At December 31, 2013, ITC Holdings and its Regulated Operating Subsidiaries had the following unsecured revolving credit facilities available, each of which bears interest at a variable rate based on the prime rate or LIBOR (subject to adjustment based on credit rating):

(Amounts in millions)	Total Available Capacity		Outstanding Balance (a)		Unused Capacity		Weighted Average Interest Rate on Outstanding Balance		Commitment Fee Rate (b)		Original Term	Date of Maturity
Revolving Credit Agreements:
ITC Holdings	$	200.0	$	—	$	200.0	n/a	(c)	0.20	%	5 years	May 2016
ITCTransmission	100.0		41.1		58.9		1.3%		0.125	%	5 years	May 2016
METC	100.0		67.2		32.8		1.3%		0.125	%	5 years	May 2016
ITC Midwest	175.0		111.0		64.0		1.2%		0.10	%	5 years	May 2017
ITC Great Plains	150.0		51.9		98.1		1.9%		0.25	%	4 years	February 2015
Total	$	725.0	$	271.2	$	453.8

____________________________

(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) Amounts outstanding would bear interest at a rate equal to LIBOR plus an applicable margin of 1.50% or at a base rate, which is defined as the higher of the prime rate, 0.50% above the federal funds rate or 1% above the one month LIBOR, plus an applicable margin of 0.50%, subject to adjustments based on ITC Holdings’ 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, 2013, we are in compliance with all debt covenants.

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EARNINGS PER SHARE Schedule of Basic and Diluted Earnings Per Common Share (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended																12 Months Ended
	Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013		Dec. 31, 2012		Sep. 30, 2012		Jun. 30, 2012		Mar. 31, 2012		Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Numerator:
NET INCOME	$ 76,937	[1],[2]	$ 58,984	[1],[2]	$ 47,395	[1],[2]	$ 50,190	[1],[2]	$ 48,256	[1]	$ 51,183	[1]	$ 42,386	[1]	$ 46,051	[1]	$ 233,506	[1],[2]	$ 187,876	[1]	$ 171,685
Dividends declared																	84,104		75,124		70,305
Undistributed earnings																	149,402		112,752		101,380
Percentage allocated to common shares																	99.10%	[3]	98.70%	[3]	98.30%	[3]
Numerator for basic and diluted earnings per common share																	231,408		185,488		168,857
Denominator:
Denominator for basic earnings per common share — weighted average common shares																	51,912,128		50,820,838		50,289,905
Incremental shares for stock options and employee stock purchase plan — weighted average assumed conversion																	429,540		742,557		788,918
Denominator for diluted earnings per common share — adjusted weighted average shares and assumed conversion																	52,341,668		51,563,395		51,078,823
Per common share net income:
Basic	$ 1.47	[1]	$ 1.12	[1]	$ 0.90	[1]	$ 0.96	[1]	$ 0.93	[1]	$ 0.99	[1]	$ 0.82	[1]	$ 0.90	[1]	$ 4.46	[1]	$ 3.65	[1]	$ 3.36
Diluted	$ 1.45	[1]	$ 1.12	[1]	$ 0.90	[1]	$ 0.95	[1]	$ 0.92	[1]	$ 0.98	[1]	$ 0.81	[1]	$ 0.88	[1]	$ 4.42	[1]	$ 3.60	[1]	$ 3.31
Percentage allocated to common shares:
Weighted average restricted shares and deferred stock units (participating securities)																	490,989		658,835		854,717
Denominator for percentage allocated to common shares — total weighted average shares outstanding																	52,403,117		51,479,673		51,144,622
Common Shares
Numerator:
Dividends declared																	83,351		74,202		69,200
Undistributed earnings																	$ 148,057		$ 111,286		$ 99,657

[1] During the years ended December 31, 2013 and 2012, we expensed external legal, advisory and financial services fees of $43.1 million and $19.4 million, respectively, and internal labor and related costs of approximately $7.8 million and $7.1 million, respectively, related to the Entergy Transaction. 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.

[2] 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 for the external costs related to the Entergy transaction incurred in 2013, 2012 and 2011 that originally were recorded as non-deductible for income tax provision purposes.

[3] Weighted-average common shares outstanding51,912,128 50,820,838 50,289,905Weighted-average restricted shares and deferred stock units (participating securities)490,989 658,835 854,717 Total52,403,117 51,479,673 51,144,622 Percentage allocated to common shares99.1% 98.7% 98.3%

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SHARE-BASED COMPENSATION Additional Information (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Apr. 30, 2007
Share-based Compensation Arrangement by Share-based Payment Award
Shares available for future issuance	1,873,658
Common Stock
Share-based Compensation Arrangement by Share-based Payment Award
Tax effects of the excess tax deductions	$ 4,300,000	$ 23,000,000	$ 28,100,000
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award
Outstanding options	1,723,276	1,603,429
Exercisable options	1,128,540	1,030,594
Term from grant date	10 years
Outstanding options - Aggregate intrinsic value	69,300,000
Outstanding options - Weighted average remaining contractual term	5 years 9 months
Exercisable options - Aggregate intrinsic value	59,600,000
Exercisable options - Weighted average remaining contractual term	4 years 3 months
Exercised options - Aggregate intrinsic value	53,200,000	53,200,000	20,500,000
Unrecognized compensation cost related to unvested awards - Total amount	6,900,000
Unrecognized compensation cost related to unvested awards - Period for recognition	1 year 11 months
Options expected to vest - Outstanding	1,698,016
Options expected to vest - Weighted average exercise price	$ 55.24
Options expected to vest - Aggregate intrinsic value	68,900,000
Options expected to vest - Weighted average remaining contractual term	5 years 9 months
Stock Options | Minimum
Share-based Compensation Arrangement by Share-based Payment Award
Vesting period	3 years
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award
Unrecognized compensation cost related to unvested awards - Total amount	17,800,000
Unrecognized compensation cost related to unvested awards - Period for recognition	2 years 2 months
Weighted average remaining contractual term	1 year 6 months
Outstanding shares	462,322	523,350
Granted - Weighted average grant date fair value	$ 88.27	$ 71.65	$ 71.27
Aggregate fair value	44,300,000
Vested in period - Aggregate fair value	15,800,000	25,100,000	20,700,000
Awards expected to vest - Outstanding	419,237
Awards expected to vest - Weighted average fair value	$ 72.60
Awards expected to vest - Aggregate intrinsic value	40,200,000
Awards expected to vest - Weighted average remaining contractual term	1 year 6 months
Long Term Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award
Authorized shares	4,950,000
Authorized shares of common stock other than options	3,250,000
Employee Stock Purchase Plan
Share-based Compensation Arrangement by Share-based Payment Award
Authorized shares				180,000
Stock purchased	25,699	25,521	23,027
Proceeds from the sale of common stock	1,900,000	1,600,000	1,300,000
Allocated share-based compensation expense	$ 400,000	$ 400,000	$ 300,000

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INCOME TAXES Income Tax Reconciliation (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Income Tax Reconciliation
Income tax expense at 35% statutory rate	$ 123,329		$ 103,778		$ 93,252
State income taxes (net of federal benefit)	9,110		6,247		4,766
AFUDC equity	(9,715)		(7,207)		(5,292)
Entergy Transaction expenses	(5,614)	[1]	4,113	[1]	1,501	[1]
Other — net	1,752		1,701		522
Total income tax provision	$ 118,862		$ 108,632		$ 94,749

[1] 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 on the Entergy Transaction.

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DEBT Additional Information (Details) (USD $)	12 Months Ended							0 Months Ended													0 Months Ended			0 Months Ended			0 Months Ended			0 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013 ITC Holdings Corp.		Dec. 31, 2012 ITC Holdings Corp.	Dec. 31, 2011 ITC Holdings Corp.	Jul. 03, 2013 ITC Holdings Corp. Term Loan Credit Agreement, due August 23, 2013	Dec. 31, 2013 ITC Holdings Corp. Term Loan Credit Agreement, due August 23, 2013 Unsecured Debt	Dec. 31, 2012 ITC Holdings Corp. Term Loan Credit Agreement, due August 23, 2013 Unsecured Debt		Aug. 23, 2012 ITC Holdings Corp. Term Loan Credit Agreement, due August 23, 2013 Unsecured Debt	Dec. 31, 2013 ITC Holdings Corp. Term Loan Credit Agreement, due December 31, 2013 Unsecured Debt	Feb. 15, 2013 ITC Holdings Corp. Term Loan Credit Agreement, due December 31, 2013 Unsecured Debt	Dec. 31, 2013 ITC Holdings Corp. Term Loan Credit Agreement, due September 30, 2016 Unsecured Debt	Dec. 20, 2013 ITC Holdings Corp. Term Loan Credit Agreement, due September 30, 2016 Unsecured Debt	Dec. 31, 2013 ITC Holdings Corp. Senior Notes, Due July 1, 2023 Unsecured Debt	Jul. 03, 2013 ITC Holdings Corp. Senior Notes, Due July 1, 2023 Unsecured Debt	Dec. 31, 2013 ITC Holdings Corp. Senior Notes, Due July 1, 2043 Unsecured Debt	Jul. 03, 2013 ITC Holdings Corp. Senior Notes, Due July 1, 2043 Unsecured Debt	Jul. 03, 2013 ITC Holdings Corp. Senior Notes due July 15, 2013	Dec. 31, 2012 ITC Holdings Corp. Senior Notes due July 15, 2013 Unsecured Debt	Dec. 31, 2013 ITCTransmission	Aug. 14, 2013 ITCTransmission Term Loan Credit Agreement, due July 14, 2014	Dec. 31, 2013 ITCTransmission Term Loan Credit Agreement, due July 14, 2014 Unsecured Debt	Jul. 11, 2013 ITCTransmission Term Loan Credit Agreement, due July 14, 2014 Unsecured Debt	Jul. 11, 2013 ITCTransmission First Mortgage Bonds, Series A, due July 15, 2013	Dec. 31, 2012 ITCTransmission First Mortgage Bonds, Series A, due July 15, 2013 Secured Debt	Aug. 14, 2013 ITCTransmission First Mortgage Bonds Series E Secured Debt	Aug. 14, 2013 ITCTransmission Intercompany Advance Agreement	Dec. 31, 2013 METC LLC	Dec. 31, 2013 METC LLC Senior Secured Notes, due October 26, 2042 Secured Debt	Dec. 31, 2012 METC LLC Senior Secured Notes, due October 26, 2042 Secured Debt	Oct. 26, 2012 METC LLC Senior Secured Notes, due October 26, 2042 Secured Debt	Jan. 31, 2014 METC LLC Term Loan Credit Agreement, Due February 2, 2015 Unsecured Debt Subsequent Event	Dec. 31, 2013 ITC Midwest LLC	Dec. 31, 2013 ITC Midwest LLC First Mortgage Bonds, Series E, due January 19, 2027 Secured Debt	Dec. 31, 2012 ITC Midwest LLC First Mortgage Bonds, Series E, due January 19, 2027 Secured Debt	Jan. 19, 2012 ITC Midwest LLC First Mortgage Bonds, Series E, due January 19, 2027 Secured Debt	Dec. 31, 2013 ITC Midwest LLC First Mortgage Bonds, Series F, due April 30, 2043 Secured Debt	Apr. 04, 2013 ITC Midwest LLC First Mortgage Bonds, Series F, due April 30, 2043 Secured Debt	Dec. 31, 2013 ITC Great Plains LLC	Dec. 31, 2013 ITC Great Plains LLC Term Loan Credit Agreement, due November 28, 2014 Unsecured Debt
Debt Instrument
Short-term debt, maximum borrowing capacity												$ 200,000,000		$ 250,000,000
Short-term debt									0	200,000,000	[1]	200,000,000	0	250,000,000.0
Other long-term debt, maximum borrowing capacity																200,000,000.0										185,000,000									50,000,000								100,000,000
Other long-term debt				140,000,000											140,000,000										0	185,000,000.0									50,000,000								100,000,000	[1]
Weighted average interest rate				0.00%	[2]										1.30%								1.30%								1.30%					1.20%						1.90%	1.00%
Principle amount																		250,000,000.0		300,000,000.0									285,000,000.0					75,000,000					100,000,000		100,000,000.0
Interest rate																	4.05%	4.05%	5.30%	5.30%		5.25%						4.45%	4.625%			3.98%	3.98%	3.98%			3.50%	3.50%	3.50%	4.09%	4.09%
Retirement of long-term debt	452,000,000	0	0	267,000,000		0	0														267,000,000						185,000,000
Repayments of debt	$ 635,000,000	$ 0	$ 0	$ 450,000,000		$ 0	$ 0	$ 200,000,000																$ 185,000,000						$ 100,000,000

[1] As of December 31, 2013 and 2012, there was $200.0 million and $651.9 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.

[2] Amounts outstanding would bear interest at a rate equal to LIBOR plus an applicable margin of 1.50% or at a base rate, which is defined as the higher of the prime rate, 0.50% above the federal funds rate or 1% above the one month LIBOR, plus an applicable margin of 0.50%, subject to adjustments based on ITC Holdings’ credit rating.

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SUBSEQUENT EVENTS (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended																12 Months Ended							12 Months Ended					12 Months Ended
	Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013		Dec. 31, 2012		Sep. 30, 2012		Jun. 30, 2012		Mar. 31, 2012		Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011	Dec. 31, 2010	Jan. 10, 2014 Stock Split	Dec. 31, 2013 Stock Split Historical		Feb. 28, 2014 Stock Split Historical	Feb. 28, 2014 Stock Split Planned	Dec. 31, 2013 Stock Split Planned	Dec. 31, 2013 Stock Split Adjustment		Dec. 31, 2013 Stock Split Pro Forma
Stockholders' Equity
Common stock, shares outstanding	52,500,265								52,248,514								52,500,265		52,248,514					52,500,265		52,500,000	157,500,000	157,500,795
Common stock, without par value, 100,000,000 shares authorized, 52,500,265 shares issued and outstanding at December 31, 2013	$ 1,014,435								$ 989,334								$ 1,014,435		$ 989,334					$ 1,014,435	[1]				$ 0	[1]	$ 1,014,435	[1]
Common stock, shares authorized	100,000,000								100,000,000								100,000,000		100,000,000				300,000,000	100,000,000
Common stock, shares issued	52,500,265								52,248,514								52,500,265		52,248,514					52,500,265				157,500,795
Retained earnings	592,970								443,569								592,970		443,569					592,970					0		592,970
Accumulated other comprehensive income	6,327								(18,048)								6,327		(18,048)		(15,368)	1,188		6,327					0		6,327
Total stockholders’ equity	1,613,732								1,414,855								1,613,732		1,414,855					1,613,732					0		1,613,732
Earnings Per Share
Numerator for basic and diluted earnings per common share																	$ 231,408		$ 185,488		$ 168,857			$ 231,408					$ 0		$ 231,408
Denominator:
Basic earnings per common share — weighted average common shares outstanding																	51,912,128		50,820,838		50,289,905			51,912,128					103,824,256		155,736,384
Diluted earnings per common share — adjusted weighted average shares and assumed conversion																	52,341,668		51,563,395		51,078,823			52,341,668					104,683,336		157,025,004
Per common share net income:
Basic	$ 1.47	[2]	$ 1.12	[2]	$ 0.90	[2]	$ 0.96	[2]	$ 0.93	[2]	$ 0.99	[2]	$ 0.82	[2]	$ 0.90	[2]	$ 4.46	[2]	$ 3.65	[2]	$ 3.36			$ 4.46					$ (2.97)		$ 1.49
Diluted	$ 1.45	[2]	$ 1.12	[2]	$ 0.90	[2]	$ 0.95	[2]	$ 0.92	[2]	$ 0.98	[2]	$ 0.81	[2]	$ 0.88	[2]	$ 4.42	[2]	$ 3.60	[2]	$ 3.31			$ 4.42					$ (2.95)		$ 1.47

[1] If the stock split had been paid at December 31, 2013, it would have increased the shares issued and outstanding on that date to 157,500,795. Authorized shares increased in January 2014 upon filing an amendment to the Articles of Incorporation with the State of Michigan.

[2] During the years ended December 31, 2013 and 2012, we expensed external legal, advisory and financial services fees of $43.1 million and $19.4 million, respectively, and internal labor and related costs of approximately $7.8 million and $7.1 million, respectively, related to the Entergy Transaction. 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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GOODWILL AND INTANGIBLE ASSETS (Tables)

12 Months Ended

Dec. 31, 2013

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Expected Amortization Expense

We expect the annual amortization of our intangible assets that have been recorded as of December 31, 2013 to be as follows:

(In thousands)
2014	$	3,276
2015	3,276
2016	3,276
2017	3,276
2018	3,276
2019 and thereafter	32,948
Total	$	49,328

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REGULATORY MATTERS Schedule of Regulatory Assets and Liabilities (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Revenue Accruals and Deferrals
Current assets	$ 6,334		$ 7,489
Non-current assets — other	3,037		2,719
Current liabilities	(33,120)	[1]	(53,763)	[1]
Non-current liabilities	(36,447)	[1]	(28,613)	[1]
Ending balance	$ (60,196)		$ (72,168)

[1] 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.

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STOCKHOLDERS EQUITY

12 Months Ended

Dec. 31, 2013

Equity [Abstract]

STOCKHOLDERS' EQUITY

STOCKHOLDERS' EQUITY

Common Stock

General — At December 31, 2013,ITC Holdings’ authorized capital stock consisted of:

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

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

As of December 31, 2013, there were 52,500,265 shares of our common stock outstanding (which includes restricted stock), no shares of preferred stock outstanding and 695 holders of record of our common stock.

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 further discussed in Note 20.

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 ITC Holdings Revolving Credit Agreement, the ITCTransmission Revolving Credit Agreement, the METC Revolving Credit Agreement, the ITC Midwest Revolving Credit Agreement, each of the ITC Great Plains Revolving and Term Loan Credit Agreements and the note purchase agreements governing ITC Holdings’ 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. ITCTransmission, METC, ITC Midwest and ITC Great Plains are restricted by their revolving credit agreements in their ability to pay dividends to ITC Holdings. In the event of default on our revolving credit agreements or non-compliance with the covenants under our revolving credit agreements, we may not be able to disburse dividends from the regulated operating subsidiaries to ITC Holdings. ITCTransmission, METC, ITC Midwest and ITC Great Plains were in compliance with the covenants under their revolving credit agreements during 2013.

In addition to the restrictions imposed by the debt covenants described above, there are practical limitations on using the net assets of each of our Regulated Operating Subsidiaries as of December 31, 2013 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 2013, 2012 and 2011, we repurchased 54,440, 99,533 and 89,715 shares of common stock for an aggregate of $4.9 million, $7.3 million and $6.4 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.

Accumulated Other Comprehensive Income

The following table provides the components of changes in AOCI for the years ended December 31, 2013, 2012 and 2011:

	Year Ended December 31,
(in thousands)	2013			2012			2011
Balance at the beginning of period	$	(18,048	)	$	(15,368	)	$	1,188
Derivative instruments
Reclassification of net gain relating to interest rate cash flow hedges from AOCI to interest expense — net (net of tax of $436, $31 and $1 for the years ended December 31, 2013, 2012 and 2011, respectively)	(25		)	67			97
Gain (loss) on interest rate swaps relating to interest rate cash flow hedges (net of tax of $15,652, $1,777 and $10,705 for the years ended December 31, 2013, 2012 and 2011, respectively)	24,329			(2,747		)	(16,653		)
Derivative instruments, net of tax	24,304			(2,680		)	(16,556		)
Available-for-sale securities
Unrealized gain on available-for-sale securities (net of tax of $46 for the year ended December 31, 2013)	71			—			—
Available-for-sale securities, net of tax	71			—			—
Total other comprehensive income (loss), net of tax	24,375			(2,680		)	(16,556		)
Balance at the end of period	$	6,327		$	(18,048	)	$	(15,368	)

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 may 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. The SAFA terminates in July 2014. The shares of common stock may be offered in one or more selling periods. Any shares of common stock sold under the SAFA will be offered at market prices prevailing at the time of sale. Moreover, ITC Holdings will specify to the sales agent (i) the aggregate selling price of the shares of common stock to be sold during each selling period, and (ii) the minimum price below which sales may not be made. ITC Holdings will pay a commission equal to a mutually agreed upon rate with its agent, not to exceed 2% of the sales price of all shares of common stock sold through its agent under the SAFA, plus expenses. The shares we would issue under the SAFA will be registered under ITC Holdings’ shelf registration statement on Form S-3 (File No. 333-187994) filed on April 18, 2013 with the SEC. No shares have been issued under this agreement.

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SEGMENT INFORMATION

12 Months Ended

Dec. 31, 2013

Segment Reporting [Abstract]

SEGMENT INFORMATION

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/
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 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

	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 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

	Regulated
	Operating		ITC Holdings			Reconciliations/
2011	Subsidiaries		and Other			Eliminations			Total
(In thousands)
Operating revenues	$	757,465	$	486		$	(554	)	$	757,397
Depreciation and amortization	94,520		461			—			94,981
Interest expense — net	58,795		88,609			(468		)	146,936
Income before income taxes	367,628		(101,194		)	—			266,434
Income tax provision (benefit)	143,416		(48,667		)	—			94,749
Net income	224,211		171,685			(224,211		)	171,685
Property, plant and equipment — net	3,404,091		11,732			—			3,415,823
Goodwill	950,163		—			—			950,163
Total assets (a)	4,711,274		2,845,182			(2,733,090		)	4,823,366
Capital expenditures	554,692		7,633			(5,394		)	556,931

____________________________

(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.

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SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT Condensed Statements of Comprehensive Income (Parent Company) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended																12 Months Ended
	Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013		Dec. 31, 2012		Sep. 30, 2012		Jun. 30, 2012		Mar. 31, 2012		Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Condensed Financial Statements, Captions
NET INCOME	$ 76,937	[1],[2]	$ 58,984	[1],[2]	$ 47,395	[1],[2]	$ 50,190	[1],[2]	$ 48,256	[1]	$ 51,183	[1]	$ 42,386	[1]	$ 46,051	[1]	$ 233,506	[1],[2]	$ 187,876	[1]	$ 171,685
OTHER COMPREHENSIVE INCOME (LOSS)
Derivative instruments (net of tax of $16,087, $1,746 and $10,704 for the years ended December 31, 2013, 2012 and 2011, respectively)																	24,304		(2,680)		(16,556)
Available-for-sale securities (net of tax of $46 for the year ended December 31, 2013)																	71		0		0
TOTAL OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX																	24,375		(2,680)		(16,556)
TOTAL COMPREHENSIVE INCOME																	257,881		185,196		155,129
ITC Holdings Corp.
Condensed Financial Statements, Captions
NET INCOME																	233,506		187,876		171,685
OTHER COMPREHENSIVE INCOME (LOSS)
Derivative instruments (net of tax of $16,087, $1,746 and $10,704 for the years ended December 31, 2013, 2012 and 2011, respectively)																	24,304		(2,680)		(16,556)
Available-for-sale securities (net of tax of $46 for the year ended December 31, 2013)																	71		0		0
TOTAL OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX																	24,375		(2,680)		(16,556)
TOTAL COMPREHENSIVE INCOME																	257,881		185,196		155,129
Statements of Comprehensive Income, Additional Disclosures
Derivative instruments, tax																	16,087		1,746		10,704
Available-for-sale securities, tax																	$ 46

[1] During the years ended December 31, 2013 and 2012, we expensed external legal, advisory and financial services fees of $43.1 million and $19.4 million, respectively, and internal labor and related costs of approximately $7.8 million and $7.1 million, respectively, related to the Entergy Transaction. 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.

[2] 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 for the external costs related to the Entergy transaction incurred in 2013, 2012 and 2011 that originally were recorded as non-deductible for income tax provision purposes.

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SIGNIFICANT ACCOUNTING POLICIES (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Accounts Receivable
Accounts receivable reserve	$ 0	$ 0
Property, Plant and Equipment
Depreciation and amortization expense	109.4	97.3	85.8
Composite depreciation rate	2.20%	2.40%	2.40%
Property, Plant and Equipment [Line Items]
AFUDC debt	8.0	7.0	4.7
Goodwill and Intangible Assets
Goodwill impairment	0
Deferred Financing Fees and Discount or Premium on Debt
Amortization of deferred financing fees and debt discounts	4.1	4.0	3.8
Asset Retirement Obligations
Asset retirement obligations	$ 5.7	$ 5.1
Minimum
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	48 years
Maximum
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	60 years

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STOCKHOLDERS' EQUITY (Tables)

12 Months Ended

Dec. 31, 2013

Equity [Abstract]

Changes in Accumulated Other Comprehensive Income

The following table provides the components of changes in AOCI for the years ended December 31, 2013, 2012 and 2011:

	Year Ended December 31,
(in thousands)	2013			2012			2011
Balance at the beginning of period	$	(18,048	)	$	(15,368	)	$	1,188
Derivative instruments
Reclassification of net gain relating to interest rate cash flow hedges from AOCI to interest expense — net (net of tax of $436, $31 and $1 for the years ended December 31, 2013, 2012 and 2011, respectively)	(25		)	67			97
Gain (loss) on interest rate swaps relating to interest rate cash flow hedges (net of tax of $15,652, $1,777 and $10,705 for the years ended December 31, 2013, 2012 and 2011, respectively)	24,329			(2,747		)	(16,653		)
Derivative instruments, net of tax	24,304			(2,680		)	(16,556		)
Available-for-sale securities
Unrealized gain on available-for-sale securities (net of tax of $46 for the year ended December 31, 2013)	71			—			—
Available-for-sale securities, net of tax	71			—			—
Total other comprehensive income (loss), net of tax	24,375			(2,680		)	(16,556		)
Balance at the end of period	$	6,327		$	(18,048	)	$	(15,368	)

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) In Thousands, unless otherwise specified	3 Months Ended																12 Months Ended
	Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013		Dec. 31, 2012		Sep. 30, 2012		Jun. 30, 2012		Mar. 31, 2012		Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
NET INCOME	$ 76,937	[1],[2]	$ 58,984	[1],[2]	$ 47,395	[1],[2]	$ 50,190	[1],[2]	$ 48,256	[1]	$ 51,183	[1]	$ 42,386	[1]	$ 46,051	[1]	$ 233,506	[1],[2]	$ 187,876	[1]	$ 171,685
OTHER COMPREHENSIVE INCOME (LOSS)
Derivative instruments, net of tax (Note 13)																	24,304		(2,680)		(16,556)
Available-for-sale securities, net of tax (Note 13)																	71		0		0
TOTAL OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX																	24,375		(2,680)		(16,556)
TOTAL COMPREHENSIVE INCOME																	$ 257,881		$ 185,196		$ 155,129

[1] During the years ended December 31, 2013 and 2012, we expensed external legal, advisory and financial services fees of $43.1 million and $19.4 million, respectively, and internal labor and related costs of approximately $7.8 million and $7.1 million, respectively, related to the Entergy Transaction. 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.

[2] 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 for the external costs related to the Entergy transaction incurred in 2013, 2012 and 2011 that originally were recorded as non-deductible for income tax provision purposes.

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COMMITMENTS AND CONTINGENT LIABILITIES (Details) (USD $)	12 Months Ended																	0 Months Ended	12 Months Ended					12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013 Customer Concentration Risk DTE Electric	Dec. 31, 2013 Customer Concentration Risk Consumers Energy	Dec. 31, 2013 Customer Concentration Risk IP&L	Dec. 31, 2013 Customer Concentration Risk Billed Revenues DTE Electric	Dec. 31, 2013 Customer Concentration Risk Billed Revenues Consumers Energy	Dec. 31, 2013 Customer Concentration Risk Billed Revenues IP&L	Dec. 31, 2013 FERC Audit Refund		Dec. 31, 2012 FERC Audit Refund		Dec. 31, 2013 ITCTransmission	Dec. 31, 2013 ITCTransmission Sales and Use Tax Audit	Dec. 31, 2013 ITCTransmission Sales and Use Tax Audit Audit Period	Dec. 31, 2013 METC LLC	May 01, 2002 METC LLC Purchase and Sale Agreement for Ancillary Services Consumers Energy	Dec. 31, 2013 METC LLC Purchase and Sale Agreement for Ancillary Services Consumers Energy	Dec. 31, 2013 METC LLC Easement Agreement Consumers Energy	Dec. 31, 2013 METC LLC Sales and Use Tax Audit	Dec. 31, 2013 ITC Midwest LLC	Dec. 31, 2013 ITC Midwest LLC Other Condition	Dec. 31, 2013 ITC Great Plains LLC Maintenance Agreement Mid-Kansas Electric Company LLC	Dec. 31, 2013 ITC Great Plains LLC Maintenance Agreement Midwest Energy
Commitments and Contingent Liabilities
Potential liability															$ 18,700,000	$ 3,800,000					$ 11,300,000
Regulatory liability	153,173,000	170,504,000								13,067,000	[1]	12,651,000	[1]
Purchase obligations	100,200,000
Rent expense	800,000	700,000	700,000
Future Minimum Lease Payments
2014	604,000
2015	237,000
2016	178,000
2017	180,000
2018 and thereafter	95,000
Total minimum lease payments	1,294,000
Other Commitments
Original term																		1 year						10 years	3 years
Automatic renewal term																			1 year	50 years				10 years	3 years
Rate of return on equity														12.38%			12.38%					12.38%
Annual cost																				10,000,000
Number of automatic renewals																				10
Reduced rate of return on equity																							10.39%
Concentration percentage							23.80%	24.00%	27.90%
Major customer revenue				$ 221,000,000	$ 222,500,000	$ 259,400,000

[1] Refer to discussion of FERC audit refund in Note 16 under “FERC Audit of ITC Midwest.” As of December 31, 2013 and 2012, the FERC audit refund was recorded in the consolidated statements of financial position in other current liabilities and other liabilities, respectively.

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SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

SIGNIFICANT ACCOUNTING POLICIES

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 transactions that would have been recorded as revenue and expense in non-regulated businesses. Regulatory assets represent costs that will be included as a component of future tariff rates and regulatory liabilities represent amounts provided in the current tariff rates that are intended to recover costs expected to be incurred in the future or amounts to be refunded to customers.

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

Consolidated Statements of Cash Flows — The following table presents certain supplementary cash flows information for the years ended December 31, 2013, 2012 and 2011:

	Year Ended December 31,
(In thousands)	2013		2012		2011
Supplementary cash flows information:
Interest paid (net of interest capitalized)	$	155,112	$	148,598	$	142,101
Income taxes paid — net	20,092		41,174		34,127
Supplementary non-cash investing and financing activities:
Additions to property, plant and equipment and other long-lived assets (a)	$	68,276	$	94,218	$	102,091
Allowance for equity funds used during construction	30,159		23,000		16,699

____________________________

(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, 2013, 2012 or 2011, 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, 2013 and 2012, 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 $109.4 million, $97.3 million and $85.8 million for 2013, 2012 and 2011, 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 2.2%, 2.4% and 2.4% for 2013, 2012 and 2011, 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 and removal costs incurred are deducted from regulatory liabilities. 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 $8.0 million, $7.0 million and $4.7 million for 2013, 2012 and 2011, 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.

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.

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. 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 by performing a qualitative analysis for each of our MISO Regulated Operating Subsidiaries as of October 1, 2013 and determined that no impairment exists. There were no events subsequent to October 1, 2013 that indicated impairment of our goodwill. 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 and the amortization of our debt discounts for 2013, 2012 and 2011 of $4.1 million, $4.0 million and $3.8 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 obligation 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 2013. Our asset retirement obligations as of December 31, 2013 and 2012 of $5.7 million and $5.1 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.

Generator Interconnection Projects — 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 have been 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 investment in transmission facilities are recorded to property, plant and equipment, and are recorded net of any contribution in aid of construction received from the generator pursuant to the provisions of the MISO or SPP tariff. 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.

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 our stock options, which have graded vesting schedules, on a straight-line basis over the requisite service period and not for each separately vesting portion of the award. 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.

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 2009 and earlier. State and city jurisdictions that remain subject to examination range from tax years 2009 to 2012. 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.

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PROPERTY, PLANT AND EQUIPMENT (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Property, Plant and Equipment
Total	$ 6,176,620	$ 5,404,389
Less: Accumulated depreciation and amortization	(1,330,094)	(1,269,810)
Property, plant and equipment — net	4,846,526	4,134,579
Regulated Operating Subsidiaries
Property, Plant and Equipment
Property, plant and equipment in service	5,641,240	4,779,833
Construction work in progress	423,433	501,847
Capital equipment inventory	75,470	86,882
Other	22,460	22,481
ITC Holdings and Other
Property, Plant and Equipment
ITC Holdings and other	$ 14,017	$ 13,346

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SHARE-BASED COMPENSATION Allocation of Share-based Compensation Costs (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Employee Service Share-based Compensation, Allocation of Recognized Period Costs
Amounts capitalized to property, plant and equipment	$ 4,731	$ 5,632	$ 5,327
Total share-based compensation	15,666	15,622	15,391
Total tax benefit recognized in the consolidated statement of operations	4,557	3,807	3,976
Operation and Maintenance Expenses
Employee Service Share-based Compensation, Allocation of Recognized Period Costs
Allocated share-based compensation expense	1,617	1,933	2,540
General and Administrative Expenses
Employee Service Share-based Compensation, Allocation of Recognized Period Costs
Allocated share-based compensation expense	$ 9,318	$ 8,057	$ 7,524

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INCOME TAXES Additional Information (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax
State income tax NOLs	$ 16,573,000	$ 11,759,000
Change in Michigan tax law	0	0	(4,638,000)
State Tax Jurisdiction
Income Tax
Federal income tax NOLs	$ 6,100,000
Michigan
Income Tax
State income tax rate			6.00%

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SUPPLEMENTARY QUARTERLY FINANCIAL INFORMATION (Unaudited)

12 Months Ended

Dec. 31, 2013

Selected Quarterly Financial Information [Abstract]

SUPPLEMENTARY QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

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
2013 (a)
Operating revenues	$	217,304	$	229,817	$	238,782	$	255,369	$	941,272
Operating income	112,881		110,994		130,822		141,364		496,061
Net income (b)	50,190		47,395		58,984		76,937		233,506
Basic earnings per share	$	0.96	$	0.90	$	1.12	$	1.47	$	4.46
Diluted earnings per share	$	0.95	$	0.90	$	1.12	$	1.45	$	4.42
2012 (a)
Operating revenues	$	196,713	$	197,375	$	214,801	$	221,646	$	830,535
Operating income	105,894		98,483		113,354		113,328		431,059
Net income	46,051		42,386		51,183		48,256		187,876
Basic earnings per share	$	0.90	$	0.82	$	0.99	$	0.93	$	3.65
Diluted earnings per share	$	0.88	$	0.81	$	0.98	$	0.92	$	3.60

____________________________

(a) During the years ended December 31, 2013 and 2012, we expensed external legal, advisory and financial services fees of $43.1 million and $19.4 million, respectively, and internal labor and related costs of approximately $7.8 million and $7.1 million, respectively, related to the Entergy Transaction. 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.

(b) 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 for the external costs related to the Entergy transaction incurred in 2013, 2012 and 2011 that originally were recorded as non-deductible for income tax provision purposes.

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RETIREMENT BENEFITS AND ASSETS HELD IN TRUST Projected Benefit Payments (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013
Defined Benefit Plans
Defined Benefit Plan Disclosure
2014	$ 1,507
2015	1,762
2016	1,661
2017	5,250
2018	5,657
2019 through 2023	33,361
Other Postretirement Benefits Plan
Defined Benefit Plan Disclosure
2014	376
2015	482
2016	599
2017	766
2018	1,184
2019 through 2023	$ 12,401

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INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2013

Income Tax Disclosure [Abstract]

Income Tax Reconciliation

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)	2013			2012			2011
Income tax expense at 35% statutory rate	$	123,329		$	103,778		$	93,252
State income taxes (net of federal benefit)	9,110			6,247			4,766
AFUDC equity	(9,715		)	(7,207		)	(5,292		)
Entergy Transaction expenses (a)	(5,614		)	4,113			1,501
Other — net	1,752			1,701			522
Total income tax provision	$	118,862		$	108,632		$	94,749

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(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 on the Entergy Transaction.

Components of Income Tax Provision

Components of the income tax provision were as follows:

(In thousands)	2013		2012		2011
Current income tax expense	$	42,159	$	41,347	$	63,952
Deferred income tax expense	76,094		66,710		33,266
Benefits of operating loss carryforward	609		575		2,169
Change in Michigan tax law	—		—		(4,638		)
Total income tax provision	$	118,862	$	108,632	$	94,749

Deferred Tax Assets and Liabilities

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

(In thousands)	2013			2012
Property, plant and equipment	$	(459,983	)	$	(378,196	)
METC regulatory deferral (a)	(13,743		)	(14,884		)
Acquisition adjustments — ADIT deferrals (a)	(14,945		)	(14,852		)
Goodwill	(117,493		)	(102,994		)
Net revenue accruals and deferrals, including accrued interest (a)	23,504			28,121
Pension and postretirement liabilities	11,864			9,706
State income tax NOLs (net of federal benefit)	16,573			11,759
Share-based compensation	12,040			10,281
Other — net	(3,530		)	14,001
Net deferred tax liabilities	$	(545,713	)	$	(437,058	)
Gross deferred income tax liabilities	$	(674,172	)	$	(572,088	)
Gross deferred income tax assets	128,459			135,030
Net deferred tax liabilities	$	(545,713	)	$	(437,058	)

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(a)Described in Note 5.

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FAIR VALUE MEASUREMENTS

12 Months Ended

Dec. 31, 2013

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

The measurement of fair value is based on a three-tier hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. Changes in economic conditions or model-based valuation techniques may require the transfer of financial instruments from one fair value level to another. In such instances, the transfer is reported at the beginning of the reporting period. For the years ended December 31, 2013 and 2012, there were no transfers between levels.

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	$	—	$	—

Our assets and liabilities measured at fair value subject to the three-tier hierarchy at December 31, 2012, 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	$	13,127	$	10,037		$	—
Mutual funds — fixed income securities	21,332		—			—
Mutual funds — equity securities	1,612		—			—
Interest rate swap derivatives	—		2,725			—
Financial liabilities measured on a recurring basis:
Interest rate swap derivatives	—		(31,507		)	—
Total	$	36,071	$	(18,745	)	$	—

As of December 31, 2013 and 2012, 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 Level 1 investments included in 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 cash and cash equivalents that are classified as a Level 2 investment consist of deposits held with financial institutions that are then invested by the financial institution in money market mutual funds and common and collective trusts that are administered similar to money market funds. The underlying money market funds and common and collective trusts are recorded at cost plus accrued interest.

The assets and liabilities related to derivatives consisted of interest rate swaps discussed in Note 8. The fair value of our interest rate swap derivatives as of December 31, 2012 was determined based on a discounted cash flow method using LIBOR swap rates which are observable at commonly quoted intervals. In June 2013, we settled and terminated all outstanding derivatives.

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, 2013 and 2012.

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 $3,299.0 million and $3,072.9 million at December 31, 2013 and 2012, 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 $3,100.9 million and $2,619.4 million at December 31, 2013 and 2012, respectively.

Revolving and Term Loan Credit Agreements

At December 31, 2013 and 2012, we had a consolidated total of $511.2 million and $527.8 million, respectively, outstanding under our revolving and term loan credit agreements, which are variable rate loans. The fair value of these loans approximates book value based on the borrowing rates currently available for variable rate loans obtained from third party lending institutions. These fair values represent Level 2 under the three-tier hierarchy described above.

Other Financial Instruments

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